10-K 1 apc201410k-10k.htm 10-K APC 2014 10K - 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, 2014
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 30, 2014, was $55.3 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 30, 2015, is shown below:
Title of Class
  
Number of Shares Outstanding
Common Stock, par value $0.10 per share
  
506,650,285
Documents Incorporated By Reference
Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 12, 2015 (to be filed with the Securities and Exchange Commission prior to April 2, 2015), 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

GENERAL

Anadarko Petroleum Corporation is among the world’s largest independent exploration and production companies, with approximately 2.9 billion barrels of oil equivalent (BOE) of proved reserves at December 31, 2014. 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 exploration and production activities worldwide, including activities in Mozambique, Algeria, Ghana, Brazil, Colombia, Côte d’Ivoire, Kenya, Liberia, New Zealand, 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, 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, oil, and NGLs.

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

Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. 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.

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Available Information  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. 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, or any amendments thereto, 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, by selecting SEC Filings on its website located at www.anadarko.com. 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 complete an information request on the Company’s website at www.anadarko.com, by selecting Investors/Shareholder Resources/Shareholder Services.
The public may read and copy any materials Anadarko files with the SEC at the SEC’s Public Reading Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reading Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website at 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.

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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 2014 and 92% of total proved reserves at year-end 2014.

Rocky Mountains Region  Anadarko’s Rocky Mountains Region (Rockies) properties include oil and natural-gas plays located in Colorado, Utah, and Wyoming where the Company operates approximately 14,500 wells and owns an interest in approximately 8,000 nonoperated wells. 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 royalty revenue from third-party activity on Land Grant acreage. The Company also believes its liquids-rich reservoirs, strong well performance, low development and operating costs, and large expandable midstream infrastructure 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. The Company focused its 2014 capital investments in areas that offer high liquids yields (liquids-rich areas), which resulted in significant oil production growth. In 2014, total-year Rockies sales volumes increased 10% over 2013, with a 45% or 49 thousand barrels of oil equivalent per day (MBOE/d) increase in liquids volumes. The Company drilled 569 wells and completed 487 wells in the Rockies during 2014. The Company plans to continue its drilling program in 2015, focusing on the Wattenberg field.

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Wattenberg  Anadarko operates approximately 5,800 vertical wells and 750 horizontal wells in the Wattenberg field. The field contains the Niobrara and Codell formations, which are naturally fractured formations that hold liquids and natural gas. During 2014, the Company’s drilling program focused entirely on horizontal development, drilling 369 horizontal wells. Sales volumes in the Wattenberg field increased 55% compared to 2013, with year-over-year increases of 69% in oil volumes and 79% in total liquids volumes. Horizontal drilling results in the Wattenberg field continue to be strong, with economics that are enhanced by the Land Grant mineral interest, a consolidated core acreage position, and recent enhancements in infrastructure and takeaway capacity.
Major facility and takeaway expansions occurred in 2014. The Lancaster cryogenic plant and Front Range Pipeline (FRP) were commissioned in 2014. The Lancaster cryogenic plant resulted in a field-wide increase in NGLs recoveries and the FRP resulted in access to the premium Mt. Belvieu NGLs market. Gas processing capacity is expected to increase in mid-2015 with the addition of Lancaster II, which is a second 300 million cubic feet per day (MMcf/d) cryogenic processing facility currently under construction. The White Cliffs pipeline expansion was completed in the third quarter of 2014, providing additional oil transportation capacity for the region. Management believes that Anadarko is well-positioned with its oil and NGLs export capacity, which includes transport by pipeline, rail, and truck.

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 and drilled 133 wells in 2014. The Company operated the field at a reduced activity level for the majority of 2014 due to capital allocation to higher-margin projects.

Powder River Deep  The Company drilled 10 horizontal wells in the Powder River basin during 2014 as part of a multi-objective horizontal exploration program targeting oil opportunities. The Company has seen encouraging results in the Niobrara and Turner formations. Anadarko controls over 350,000 acres of deep mineral rights within the Powder River basin.

Coalbed Methane Properties  Anadarko operates approximately 2,300 CBM wells and owns an interest in approximately 2,500 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 operated the field at a reduced activity level in 2014 due to capital allocation to higher-margin projects.

Salt Creek and Monell  During 2014, the Company continued the development of its Rockies EOR assets in 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 10% in 2014. In 2015, the Company plans to continue the management of these fields 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 in the Salt Creek field in Wyoming. The funding commitment was completed in 2014.

Laramie County, Wyoming  Anadarko holds ownership in more than 100,000 mineral-interest acres in this emerging liquids-rich play, targeting the Niobrara and Codell formations in the northern DJ Basin. In 2014, the Company participated in more than 70 nonoperated wells testing the Niobrara and Codell formations. Early results from wells drilled in 2014 are encouraging, as results from the 19 nonoperated wells that are currently producing remain strong with initial 30-day net production averaging approximately 1,000 barrels of oil equivalent per day (BOE/d).

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Greater Green River Basin  Anadarko operates over 1,400 wells in the Wamsutter and Moxa fields, which are primarily dry-gas assets. The Company also carries a nonoperated position in 2,600 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 late 2013, Anadarko acquired additional working interests and became the operator in the Moxa field, increasing the Company’s net production by approximately 6,500 BOE/d. In 2014, additional value was realized through reduction in the decline rates and decreasing operating costs.
In January 2014, Anadarko sold its interest in the Pinedale/Jonah assets in Wyoming for $581 million.

Southern and Appalachia Region  Anadarko’s Southern and Appalachia Region properties are primarily located in Texas, Pennsylvania, Louisiana, and Kansas. The region includes the Eagleford shale in South Texas, the Delaware basin in West Texas, the Marcellus shale in north-central Pennsylvania, 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 2014, the Company continued to focus on liquids-rich opportunities across the region by expanding drilling activity in the emerging Wolfcamp shale play in the Delaware basin and other shale plays, while continuing its existing liquids-rich projects in the Eagleford shale, 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 2014, total-year sales volumes in the Southern and Appalachia Region increased 16% over 2013, with a 33% increase in liquids volumes. The Company drilled 589 operated horizontal wells and brought 730 wells online in 2014. In 2015, the Company expects to continue its horizontal drilling program, focusing on the Texas assets.

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Eagleford  The Eagleford shale development in South Texas consists of approximately 357,000 gross acres and over 1,100 producing wells. The Company drilled 393 wells, completed 388 wells, and brought 385 wells online generating 47% sales volume growth year over year. Anadarko entered 2014 with 10 drilling rigs and reduced the rig count to eight by the end of 2014 due to outstanding drilling performance. To facilitate additional completion activities, water infrastructure was expanded in 2014, increasing capacity by 75 thousand barrels per day (MBbls/d). The Company continues to test concepts for additional recovery across its acreage position and completed successful tests on two upper-Eagleford shale wells.

Delaware Basin  Anadarko holds an interest in over 600,000 gross acres in the Delaware basin. Anadarko’s 2014 drilling activity primarily targeted the liquids-rich Bone Spring formation, the Avalon shale, and the developing Wolfcamp shale play. In 2014, Anadarko drilled 97 operated wells and participated in 43 nonoperated wells. Significant infrastructure was added, which increased NGLs sales volumes by 82% over 2013. In addition, in November 2014, Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, acquired Nuevo Midstream, LLC (Nuevo), which has gathering and processing assets located in the Delaware basin. The Company had one operated rig drilling in the Bone Spring formation, one operated rig drilling in the Avalon shale, and eight operated rigs drilling in the Wolfcamp shale at year-end 2014.
The successful Wolfcamp shale delineation program continues to deliver encouraging results across the majority of Anadarko’s acreage position. Anadarko is testing multiple zones within the Wolfcamp shale and several development concepts including multi-well pads, extended laterals, and horizontal well spacing for increased efficiency. The Company has identified thousands of potential drilling locations in the Wolfcamp formations that are expected to provide substantial opportunity for Anadarko’s continued activity in the basin.

Eaglebine  Anadarko holds 156,000 gross acres in the Eaglebine shale in Southeast Texas, most of which is held by existing Austin Chalk production. In 2014, Anadarko continued to delineate and develop this acreage with a one-rig drilling program. In September 2014, the Company entered into a carried-interest arrangement requiring a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development. Anadarko will remain the operator with an average post-transaction working interest of approximately 51%. This transaction allows the Company to develop this oil opportunity while further enhancing Anadarko’s capital efficiency and flexibility. At December 31, 2014, $22 million of the total $442 million obligation had been funded.

East Texas/North Louisiana  Anadarko holds 293,000 gross acres in East Texas/North Louisiana. Anadarko increased its capital program in the East Texas Carthage area in 2014, targeting a liquids-rich area in the Haynesville shale. In 2014, Anadarko operated six rigs and drilled 52 wells in the Haynesville and Cotton Valley formations. The Company increased sales volumes from the area by 10% year over year.

Marcellus  The Company holds 654,000 gross acres in the Marcellus shale of the Appalachian basin. During the year, 24 operated horizontal wells were drilled using one rig. Anadarko also participated in drilling an additional 78 nonoperated horizontal wells in 2014. The Company’s production in Marcellus continued to improve with sales volumes increasing 12% over 2013.

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Gulf of Mexico  In the Gulf of Mexico, Anadarko owns an average 61% working interest in 394 blocks. The Company operates seven active floating platforms and holds interests in 23 producing fields. During 2014, the Company advanced development of the Lucius and Heidelberg projects and continued an active deepwater development 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 in the Gulf of Mexico during 2014.

Development
Lucius  The Company realized first production at the Anadarko-operated Lucius Spar in January 2015, bringing on three wells initially and ramping up production with an additional three wells expected to come online during the first quarter of 2015. The successful Lucius project was developed with production startup only three years from sanction and five years from discovery. The 80-MBbls/d spar resides in Keathley Canyon Block 875 with a water depth of 7,100 feet.
A carried-interest arrangement with a third party, entered into in 2012, provided funding for the substantial majority of Anadarko’s development capital commitment through first production. Following the carried-interest arrangement and 2014 equity re-determination, the Company holds a 23.8% working interest in Lucius.

Heidelberg  The Company continues to advance the Anadarko-operated Heidelberg development project, which was sanctioned during the second quarter of 2013. The construction of the 80-MBbls/d spar is progressing on schedule with anticipated start-up in 2016. At December 31, 2014, fabrication of the main topsides module was more than 70% complete and ahead of schedule.
In 2013, the Company entered into a carried-interest arrangement requiring a third party to fund $860 million of capital costs in exchange for a 12.75% working interest in the project. The carry obligation is expected to cover the substantial majority of the Company’s expected future capital costs through first production. At December 31, 2014, $386 million of the $860 million obligation had been funded. Anadarko holds a 31.5% working interest in Heidelberg. Development drilling commenced in late 2014 on two development wells.

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Caesar/Tonga  At Caesar/Tonga (33.75% working interest), the Company successfully completed a fourth development well (GC 727#2) in the first quarter of 2014, and the well is producing 10 MBbls/d of oil. Anadarko is currently completing a fifth development well (GC 683#2), which is expected to come online during the first quarter of 2015.

K2  At K2 (41.8% working interest), the GC 562 #5 infill well found 210 feet of oil pay in the Miocene, and the well is being sidetracked for a subsequent completion. The well is expected to come online in the second half of 2015.

Constitution  At Constitution (100% working interest), the Company executed a successful platform drilling program in 2014, where the A1 well was sidetracked, completed, and brought online producing 3 MBbls/d of oil.

Vito  In 2014, Anadarko sold its 18.67% working interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks, for $500 million.

Exploration
Three exploration wells were drilled in the Gulf of Mexico during 2014. The Deep Nansen exploration well (35% working interest) targeted Lower Tertiary-aged sediments in a large, four-way structure beneath Anadarko’s Nansen field and found non-commercial quantities of hydrocarbons and the well was plugged and abandoned. The evidence of a working petroleum system is being incorporated into potential future activity on the surrounding leasehold. The Bimini exploration well (50% working interest) was drilled in Garden Banks close to existing infrastructure at the Anadarko-operated Power Play field and near the Conger field and Baldpate Platform. The well tested a subsalt Miocene prospect and was plugged and abandoned. The K2 development well was drilled deeper to test the Wilcox potential beneath the existing field in Green Canyon and did not find commercial quantities of hydrocarbons in the Wilcox objective. The K2 well will be sidetracked and completed in a field pay interval. Also, the Yeti exploration well (37.5% nonoperated working interest) was spud prior to year end. The well will test a Miocene sub-salt three-way closure in Walker Ridge.

Appraisal
Shenandoah Basin  The Company spud the Shenandoah-3 well, its second appraisal well at the Shenandoah discovery, in the second quarter of 2014. The well finished drilling at the end of 2014 and found approximately 50% (1,470 feet) more of the same reservoir sands 1,500 feet down-dip and 2.3 miles east of the Shenandoah-2 well, which encountered over 1,000 feet of net oil pay in excellent quality Lower Tertiary-aged sands. The Shenandoah-3 well confirmed the sand depositional environment, lateral sand continuity, excellent reservoir qualities, and down-dip thickening. The well also enabled the projection of oil-water contacts based on pressure data and reduced the uncertainty of the resource range. Planning is underway for the next appraisal well, which the Company expects to spud in the second quarter of 2015.
An appraisal well at the Coronado discovery (35% working interest) reached total depth during the second quarter of 2014 and did not find the Lower Miocene objective and was plugged and abandoned.
During the third quarter of 2014, the first appraisal well of the Yucatan discovery (25% working interest) was drilled down-dip of the original discovery, and found approximately 57 gross feet of pay in Lower Tertiary oil-bearing sands. The Yucatan discovery is located approximately three miles south of the Shenandoah discovery.
 
Alaska  Anadarko’s nonoperated oil production and development activity in Alaska is concentrated on the North Slope. Infrastructure construction began in 2013 on the Alpine West satellite development, a 15-to-20-well extension of the Alpine field. Drilling at Alpine West is scheduled to commence in mid-2015 with production anticipated to come online in late 2015 or early 2016.

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International

Overview  Anadarko’s international operations include oil, natural-gas, and NGLs production and development in Mozambique, Algeria, and Ghana. The Company also has exploration acreage in Brazil, Colombia, Côte d’Ivoire, Ghana, Kenya, Liberia, Mozambique, New Zealand, and other countries. International locations accounted for 11% of Anadarko’s total sales volumes and 21% of sales revenues during 2014, and 8% of total proved reserves at year-end 2014. In 2015, the Company expects to focus its exploration and appraisal activity in East Africa, Côte d’Ivoire, and Colombia.
Mozambique  Anadarko operates two blocks (one onshore and one offshore) totaling approximately 5.3 million gross acres at December 31, 2014. From a construction, finance, and marketing perspective, the Company is positioned to commence project execution and deliver first cargoes in the expected 2019 timeframe; however, the pace of this project is dependent upon securing necessary approvals from the government of Mozambique.

Development In February 2014, the Company sold a 10% working interest in Offshore Area 1 in Mozambique for $2.64 billion. Anadarko remains the operator of Offshore Area 1 with a working interest of 26.5%.
During 2014, the Company obtained reserves certification from a third party indicating sufficient volumes to support an initial LNG development. The Environmental Impact Assessment was approved by the government of Mozambique. The Company completed front-end engineering and design (FEED) for the onshore liquefaction facilities and the offshore gathering infrastructure and is in the process of selecting the contractor groups for construction. Anadarko and its partners reached non-binding Heads of Agreements for long-term LNG sales to buyers in Asian markets covering in excess of eight million metric tonnes per annum. In December 2014, the Mozambique government published a Decree Law that is sufficient to continue progressing project finance, marketing, and construction and operation of an LNG project. This legislation marks a critical step toward establishing a project-wide legal and contractual framework that delivers a level of fiscal stability enabling continued equity investments by the Company and potential access to significant limited-recourse project finance capital.

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Exploration  In the Offshore Area 1, the Tubarão Tigre-1 exploration well was drilled approximately 37 miles south of the Orca-1 discovery well and encountered more than 92 feet of net gas pay in Paleocene sands. The Ouriço do Mar exploration well was drilled 22.5 miles south of the Orca-1 discovery well and tested the potential down-dip extent of the Paleocene reservoirs found in the Orca and Tubarão Tigre discoveries. The well was plugged and abandoned during the third quarter of 2014. Appraisal of the Orca discovery continued with the drilling of three appraisal wells. During the first quarter of 2014, the Orca-2 well encountered 151 feet of Paleocene reservoir sand with the top 26 feet being charged, establishing the gas/water contact for the discovery. The rig moved to the Orca-3 location and encountered 102 net feet of natural-gas pay in the Paleocene. The Orca-4 well reached total depth during the fourth quarter of 2014 encountering natural-gas pay in two reservoirs. At the end of 2014, the rig was located at Tubarão Tigre-2 drilling the first appraisal well associated with the Tubarão Tigre discovery. Data from these wells will be used to further delineate the size of the resource and determine future appraisal activity for the Orca and Tubarão Tigre discoveries.
In the Onshore Rovuma (35.7% working interest), the Anadarko-operated Tembo-1 well completed drilling at the end of the fourth quarter in 2014. The well encountered gas and condensate in one of the Cretaceous reservoirs and post-drill evaluations are underway to determine if additional exploration is warranted within the prospect area. A rig has been mobilized to the second well in the program, Kifaru, which will test Miocene, Oligocene, and Paleocene gas targets near the future LNG facility site.
 
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 (CPF) in Block 404 and oil, condensate, and NGLs through the El Merk CPF in Block 208. Gross production through these facilities averaged more than 383 MBbls/d in 2014, and a quarterly net production record of approximately 75 MBOE/d was achieved as all of the fields at the El Merk CPF were increased to full oil production rates. The Company drilled nine 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.
The Jubilee field (27% nonoperated unit interest), which spans both the West Cape Three Points Block and the Deepwater Tano Block, averaged gross production of 102 MBbls/d of oil in 2014. In the fourth quarter of 2014, a pipeline tie-in was completed and natural-gas exports commenced from the Jubilee field to an onshore gas processing plant. The natural-gas exports are being delivered to satisfy a commitment established in conjunction with the Jubilee development plan and are expected to allow increases in future oil production rates. The Company and its partners are evaluating options to further expand the oil throughput capacity of the floating production, storage, and offloading vessel (FPSO) and expect to submit a full-field development plan for the Jubilee field to the government of Ghana in 2015.
The Jubilee J-24 development well was drilled deeper to evaluate the Mahogany sands below the Jubilee reservoirs. Additional appraisal work was completed in 2014 in the Mahogany and Akasa fields and the data is under evaluation.
In 2013, development commenced on the Tweneboa/Enyenra/Ntomme (TEN) project (19% nonoperated working interest). The project will use an 80-MBbls/d-capacity FPSO for production from subsea wells. Significant progress was made during 2014, including engineering design completion, the successful dry-docking of the FPSO, and drilling of the first nine wells. The project was approximately 50% complete at year-end 2014 and remains on budget and on schedule for first production in 2016.

China  In August 2014, the Company sold its Chinese subsidiary for $1.075 billion.

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Brazil  Anadarko holds exploration interests in approximately 300,000 gross acres in two offshore blocks located in the Campos basin. At the Wahoo discovery, the Company is evaluating commercialization options by performing pre-FEED and FEED studies.

Colombia  During 2014, Anadarko was the high bidder on the COL1, COL 6, and COL 7 blocks. At December 31, 2014, Anadarko controls the exclusive rights to explore or conduct technical evaluation activities on nine blocks, totaling 16 million acres. The COL 1, COL 2, COL 6, and COL 7 blocks are operated at 100% working interest and the remaining blocks are operated at a 50% working interest.
Two initial prospects have been selected for the 2015 exploration drilling program. The Calasu prospect is a large four-way structure on the north end of the Fuerte Norte block. It has multiple targets and success would reduce the risk of several adjacent structures on the block. The Kronos prospect is located in the Fuerte Sur block and will test a large structure associated with the frontal area of a large thrust complex. As with Calasu, success would reduce the risk of multiple prospects. The two-well program commenced in early 2015.

Côte d’Ivoire  Anadarko owns an operated working interest in five offshore blocks totaling approximately 1.3 million acres, including CI-515 and CI-516 each with a 45% working interest, CI-103 with a 65% working interest, and CI-528 and CI-529 each with a 90% working interest.
The Company continued appraisal of the Cretaceous Paon discovery in Block CI-103, where the discovery well encountered 100 feet of net pay. The Paon-3AR was drilled 3.7 miles down-dip to the discovery well and encountered more than 94 feet of pay. The well established an oil/water contact and appears to be in communication with the Paon-1X discovery. As a result of the success, the drilling of the Paon-4A was accelerated. The well, located six miles east of the Paon-3AR, penetrated over 37 feet of pay in the target section and defined the eastern extent of the reservoir. During 2014, Anadarko became operator of the block and farmed down a portion of the working interest for a carry on the appraisal activities. Based on the successful drilling program to date, the partnership and the government are currently discussing additional appraisal drilling activity for 2015, which would include a drillstem test.
The Morue prospect in Block CI-516 was drilled and encountered a small accumulation of oil in the well-developed sands in the targeted interval, and was plugged and abandoned as non-commercial.
The Saumon prospect was drilled in Block CI-515 during 2014. The well reached total depth and did not find hydrocarbons. The well was plugged and abandoned.

Kenya  Anadarko owns and operates a 45% working interest in five offshore deepwater blocks, encompassing approximately 5.6 million gross acres. An exploration well is currently planned to test a large four-way structure at the Mlima prospect in Block L-11B during 2015.

Liberia  Two exploration wells were drilled in Block LB-10 (50% working interest) during 2014. The Anadarko-operated Iroko and Timbo wells both encountered non-commercial quantities of oil in their primary targets and were plugged and abandoned. Post-well evaluation is underway to determine the remaining prospectivity of the block. Anadarko completed a farm down prior to drilling, which covered a majority of the drilling costs for these two wells.

New Zealand  Anadarko controls the exclusive rights to explore or conduct technical evaluation activities on four blocks totaling 42 million acres, of which 6.1 million acres are owned under exploration licenses. Anadarko operates a 45% working interest in the Canterbury basin block and a 100% working interest in two Pegasus basin blocks. In the 36 million acre New Caledonia basin block, Anadarko controls a 25% nonoperated working interest. The Caravel prospect reached its total-depth objective in the Canterbury basin block and was plugged and abandoned, having encountered natural gas shows and high-quality reservoir in the primary objective. A seismic acquisition is planned during 2015 on the block.

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

12


Proved Reserves

Estimates of proved reserves volumes owned at year end, net of third-party royalty interests, are presented in billions of 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. Proved reserves are estimated based on the average beginning-of-month prices during the 12-month period for the respective year.
Disclosures by geographic area include the United States and International. The International geographic area consists of proved reserves located in Algeria and Ghana, which by country and in total represents less than 15% of the Company’s total proved reserves. The Company sold its Chinese subsidiary during 2014.

Summary of Proved Reserves
 
Natural Gas
(Bcf)
 
Oil and
Condensate
(MMBbls)
 
NGLs
(MMBbls)
 
Total
(MMBOE)
December 31, 2014
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
6,635

 
352

 
304

 
1,762

International
27

 
190

 
13

 
207

Undeveloped
 
 
 
 
 
 
 
United States
2,033

 
352

 
162

 
853

International
4

 
35

 

 
36

Total proved
8,699

 
929

 
479

 
2,858

 
 
 
 
 
 
 
 
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


The Company’s year-end 2014 proved reserves product mix was comparable to the last two years with 51% natural gas, 33% oil and condensate, and 16% NGLs.

13


Anadarko is focused on growth and profitability, and reserves replacement is a key to growth. Future profitability partially depends on commodity prices and the cost of finding and developing oil and gas reserves. Reserves growth can be achieved through successful exploration and development drilling, improved recovery, or acquisition of producing properties.

MMBOE
2014
 
2013
 
2012
Proved Reserves
 
 
 
 
 
January 1
2,792

 
2,560

 
2,539

Reserves additions and revisions
 
 
 
 
 
Discoveries and extensions
63

 
145

 
82

Infill-drilling additions (1)
577

 
410

 
383

Drilling-related reserves additions and revisions
640

 
555

 
465

Other non-price-related revisions (1)
(137
)
 
(40
)
 
(31
)
Net organic reserves additions
503

 
515

 
434

Acquisition of proved reserves in place

 
36

 
4

Price-related revisions (1)
(1
)
 
(23
)
 
(68
)
Total reserves additions and revisions
502

 
528

 
370

Sales in place
(124
)
 
(12
)
 
(81
)
Production
(312
)
 
(284
)
 
(268
)
December 31
2,858

 
2,792

 
2,560

Proved Developed Reserves
 
 
 
 
 
January 1
2,003

 
1,883

 
1,811

December 31
1,969

 
2,003

 
1,883

_______________________________________________________________________________
(1) 
Combined and reported as revisions of prior estimates in the Company’s Supplemental Information under Item 8 of this Form 10-K. Reserves bookings related to infill drilling additions are treated as positive revisions. Other non-price-related revisions in 2014 are driven by a reduction of 116 MMBOE in the Wattenberg area primarily associated with the optimization of horizontal drilling locations and the discontinuation of vertical well workover plans.

The Company’s estimates of proved developed reserves, proved undeveloped reserves (PUDs), and total proved reserves at December 31, 2014, 2013, and 2012, 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. 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 Critical Accounting Estimates under Item 7 of this Form 10-K for additional information on the Company’s proved reserves.
The Company has not yet filed information with a federal authority or agency with respect to its estimated total proved reserves at December 31, 2014. 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.

14


Changes in PUDs  Changes to PUDs occurring during 2014 are summarized in the table below. Revisions of prior estimates reflect Anadarko’s ongoing evaluation of its asset portfolio and 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. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUDs development within five years unless specific circumstances warrant a longer development time horizon.
MMBOE
 
PUDs at January 1, 2014
789

Revisions of prior estimates
333

Extensions, discoveries, and other additions
32

Conversion to developed
(210
)
Sales
(55
)
PUDs at December 31, 2014
889


Revisions In 2014, PUD revisions of 333 MMBOE were primarily related to successful infill drilling in large onshore areas such as Wattenberg in the Rockies and the Eagleford shale in the Southern and Appalachia Region, partially offset by decreases primarily due to development plan updates.

Extensions, Discoveries, and Other Additions During 2014, Anadarko added 32 MMBOE of PUDs through extensions, discoveries, and other additions, primarily as a result of successful drilling in the Marcellus and Wolfcamp shale plays in the Southern and Appalachia Region.

Conversions  In 2014, the Company converted 210 MMBOE, or 27% of total year-end 2013 PUDs, to developed status. Approximately 73% of PUD conversions occurred in U.S. onshore assets, 16% in international assets, and the remaining 11% in Gulf of Mexico assets.
Development activity in the U.S. onshore assets resulted in the conversion of 80 MMBOE in the Southern and Appalachia Region and 72 MMBOE in the Rockies. Ongoing development activity in the Company’s Algerian assets resulted in the conversion of 34 MMBOE in 2014. The remaining PUD conversions were associated with development projects in various Gulf of Mexico fields.
Anadarko spent $1.6 billion to develop PUDs in 2014, of which approximately 74% related to U.S. onshore assets, 13% related to Gulf of Mexico assets, and 13% related to international assets.
In 2013, the Company converted 183 MMBOE, or 27% of the 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. Anadarko spent $1.0 billion on PUD development 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.

15


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, 2014, 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, 2014, the Company had 39 MMBOE of pre-2010 PUDs that remained undeveloped. Approximately 51% of these PUDs are associated with Gulf of Mexico opportunities where longer development times are a result of delays associated with operating in a deepwater environment, including delays associated with the development and adoption of enhanced safety procedures and other regulatory changes following the Deepwater Horizon event.
Another 33% of the Company’s pre-2010 PUDs are associated with the Salt Creek EOR single-development project located in the Rockies. Since 2003, Anadarko has invested an average of $90 million per year to develop the Salt Creek EOR project and will continue similar spending levels in the future.
The remaining pre-2010 PUDs are associated with the El Merk development project and are being developed according to an Algerian government-approved plan. Anadarko and its partners achieved initial oil production in 2013 and the El Merk facility reached maximum allowable oil production rates in 2014 when all the fields were brought online and the facility became fully operational.

Technologies Used in Proved Reserves Estimation  The Company’s 2014 proved reserves additions were based on estimates generated through the integration of relevant geological, engineering, and production data, using 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 used 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).
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.

16


The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserves estimates, has over 28 years of experience in the oil and gas industry, including over 14 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 28 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 the Company’s estimates of proved reserves and future net cash flows at December 31, 2014. 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 were limited reviews of Anadarko’s procedures and methods and do 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 16 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, 2014. 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 308 MMBOE for 2014, 285 MMBOE for 2013, and 268 MMBOE for 2012. Production costs are costs to operate and maintain the Company’s wells, related equipment, and supporting facilities, including the cost of labor, well service and repair, location maintenance, power and fuel, gathering, processing, 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 20—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)
 
2014

 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Natural Buttes
154

 
1

 
4

 
31

 
$
3.93

 
$
81.74

 
$
39.16

 
$
10.30

Wattenberg
125

 
27

 
13

 
62

 
4.19

 
87.76

 
36.46

 
8.00

Other United States
666

 
46

 
26

 
182

 
4.08

 
88.29

 
34.29

 
9.28

Total United States
945

 
74

 
43

 
275

 
4.07

 
87.99

 
35.48

 
9.11

International

 
32

 
1

 
33

 

 
99.79

 
56.16

 
8.22

Total
945

 
106

 
44

 
308

 
4.07

 
91.58

 
36.01

 
9.01

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

 _______________________________________________________________________________
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 oil and natural gas under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities. At December 31, 2014, Anadarko was contractually committed to deliver approximately 874 Bcf of natural gas to various customers in the United States through 2031. These contracts have various expiration dates with approximately 45% of the Company’s current commitment to be delivered in 2015, and 70% by 2019. At December 31, 2014, Anadarko also was contractually committed to deliver approximately 9 MMBbls of oil to ports in Algeria and Ghana through 2015. 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, 2014:
 
Developed
Lease
 
Undeveloped
Lease
 
Fee Mineral
 
Total
thousands of acres
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Onshore
5,069

 
3,314

 
5,203

 
2,140

 
10,313

 
8,472

 
20,585

 
13,926

Offshore
293

 
139

 
2,079

 
1,401

 

 

 
2,372

 
1,540

Total United States
5,362

 
3,453

 
7,282

 
3,541

 
10,313

 
8,472

 
22,957

 
15,466

International
499

 
113

 
56,725

 
39,328

 

 

 
57,224

 
39,441

Total
5,861

 
3,566

 
64,007

 
42,869

 
10,313

 
8,472

 
80,181

 
54,907


At December 31, 2014, the Company had approximately 26 million net undeveloped lease acres scheduled to expire by December 31, 2015, 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 2014 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 2014 consisted of 88 gross completed wells, which included 71 U.S. onshore wells, five Gulf of Mexico wells, and 12 international wells. Development activity in 2014 consisted of 1,268 gross completed wells, which included 1,264 U.S. onshore wells and four Gulf of Mexico 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
 
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
35.6

 
1.6

 
37.2

 
811.4

 
6.0

 
817.4

 
854.6

International
0.9

 
4.5

 
5.4

 

 

 

 
5.4

Total
36.5

 
6.1

 
42.6

 
811.4

 
6.0

 
817.4

 
860.0

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


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, 2014:
 
Wells in the process
of drilling or
in active completion
 
Wells suspended or
waiting on completion (1)
 
Exploration
 
Development
 
Exploration
 
Development
United States
 
 
 
 
 
 
 
Gross
7

 
186

 
60

 
861

Net
3.8

 
118.6

 
28.2

 
557.9

International
 
 
 
 
 
 
 
Gross
2

 

 
57

 
19

Net
0.9

 

 
17.8

 
4.2

Total
 
 
 
 
 
 
 
Gross
9

 
186

 
117

 
880

Net
4.7

 
118.6

 
46.0

 
562.1

 _______________________________________________________________________________
(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, 2014, the Company’s ownership interest in productive wells was as follows:
 
Oil Wells (1)
 
Gas Wells (1)
United States
 
 
 
Gross
4,611

 
28,200

Net
3,157.9

 
19,271.8

International
 
 
 
Gross
201

 
4

Net
36.1

 
1.0

Total
 
 
 
Gross
4,812

 
28,204

Net
3,194.0

 
19,272.8

________________________________________________________________
(1) 
Includes wells containing multiple completions as follows:
Gross
245

 
2,862

Net
216.8

 
2,401.4


MIDSTREAM PROPERTIES AND ACTIVITIES

Anadarko invests in and operates 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 WES, which is a publicly traded limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. WES’s general partner interest is owned by Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary formed to own substantially all of the partnership interests in WES previously owned by Anadarko. At December 31, 2014, Anadarko’s ownership interest in WGP consisted of an 88.3% limited partner interest and the entire non-economic general partner interest. At December 31, 2014, WGP’s ownership interest in WES consisted of a 34.9% limited partner interest, the entire 1.8% general partner interest, and all of the WES incentive distribution rights. At December 31, 2014, Anadarko also owned an 8.3% limited partner interest in WES through other subsidiaries.
At the end of 2014, Anadarko had 41 gathering systems and 38 processing and treating plants located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, Pennsylvania, and Texas. In 2014, 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 2015, the Company plans to continue midstream investments in these core areas.

Wattenberg  The Company is constructing a second 300-MMcf/d train at its Lancaster cryogenic processing plant, with completion expected in the second quarter of 2015. The plant will support the increasing production from horizontal drilling in the Niobrara development, helping to relieve processing constraints and improve recoveries of NGLs in the basin. Three new compressor stations are scheduled to come online in the first quarter of 2015 with a total capacity of 120 MMcf/d. In addition, the Company is constructing a Central Oil Stabilization Facility (COSF) with an expected completion date of mid-year 2015. The COSF will stabilize oil in a centralized location and will reduce equipment and installation cost at each well pad. Initial planned throughput for the facility is 125 MBbls/d.

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The Company participates in two long-haul NGL pipeline joint ventures, FRP and Texas Express Pipeline (TEP), which provide access to the Gulf Coast NGLs market. The FRP, which is connected to the Company’s Lancaster processing facility, was placed in service in the first quarter of 2014. The FRP extends 435 miles, providing 150 MBbls/d (expandable to 230 MBbls/d) of NGLs takeaway capacity from Weld County, Colorado to Skellytown, Texas. In Skellytown, the FRP connects to other pipelines including the TEP. The TEP extends 593 miles providing 280 MBbls/d (expandable to 400 MBbls/d) of NGLs takeaway capacity to NGLs fractionation and storage facilities in Mont Belvieu, Texas. The Company has ownership interests of 33% in the FRP, 20% in the TEP, and 25% in two NGLs fractionators at Mont Belvieu.
In July 2014, construction of the second pipeline for the White Cliffs Pipeline system was completed and placed in service. This 526-mile dual pipeline system now provides 150 MBbls/d of oil takeaway capacity from Platteville, Colorado to Cushing, Oklahoma. The Company and its joint-venture partners are currently expanding the existing pipeline system to over 200 MBbls/d. The expansion project is scheduled to be completed in mid-2015.

Greater Natural Buttes  Chipeta’s total processing capacity (cryogenic and refrigeration) is approximately one billion cubic feet per day with cryogenic processing capacity exceeding 600 MMcf/d. Chipeta’s third-party pipeline interconnect has added over 100 MMcf/d of natural-gas supply to the plant. Optimization projects, including several pipeline-freeze mitigation projects in the gathering system, have continued to improve the Company’s reliability and efficiency.

Wyoming  During the second half of 2014, the Company connected five third-party well locations to the Patrick Draw plant. Initial deliveries are expected in the first quarter of 2015. The Company also constructed a 10-mile pipeline in the Barricade unit to gather and deliver the incremental third-party gas to the Company’s Patrick Draw plant for processing. Also, gathering connections and expansions in 2014 increased throughput of the Hilight plant by about 40%.

Delaware Basin  In 2014, the Company expanded its midstream infrastructure for Bone Spring, Wolfcamp, and Avalon production in the Delaware basin of West Texas, installing a total of 127 miles of oil and gas gathering lines. Also, significant progress was made towards expanding three central production facilities that will add 30 MBbls/d of capacity upon completion in early 2015. Substantial progress was made on a new CGF with a capacity of 24 MMcf/d, which will be completed in early 2015. The Company entered into a joint-venture agreement with a third party to construct a new 200-MMcf/d cryogenic plant located in Loving County, Texas. The new plant will be operated by the third party.
In November 2014, WES acquired Nuevo, which owns and operates gathering and processing assets located in the Delaware basin. Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM). The assets include a 300-MMcf/d cryogenic gas processing plant. WES is preparing to construct an additional 200-MMcf/d cryogenic unit (Train IV) and progress payments have been made towards the construction of another cryogenic unit (Train V), with both expected to come online in 2016.

Eagleford  In the Eagleford shale, Anadarko continued the expansion of its infield gathering system with (i) the installation of two new field gas compression facilities, (ii) the addition of incremental compression at Stumberg and Catarina Ranch compressor stations, and the Maverick main central delivery point compression facilities, as well as three other existing field compression facilities, (iii) the completion of approximately 90 miles of gathering pipelines and lateral that connected more than 20 central production facilities, and (iv) enhancements at the main oil-handling facility that increased its reliability and capabilities. The 200-MMcf/d Brasada natural-gas cryogenic processing plant completed its first full year of operations and remains at or near capacity.

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East Texas/North Louisiana  In East Texas, the Company continued to expand its midstream infrastructure for Cotton Valley Taylor and Haynesville production in 2014. 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 430 MMcf/d of firm-processing capacity for the Company’s current and future development in East Texas.

Marcellus  In the Marcellus shale, Anadarko continued to expand its gathering system in Lycoming County, Pennsylvania. In 2014, the Company connected 44 Anadarko-operated wells and constructed 52 miles of new pipeline. The Seely West trunk line, completed in December 2014, connects the COP 356/357 gathering system and Larry’s Creek gathering system to the Seely gathering system and alleviates the need to use third parties to gather natural gas.

Springfield  In September 2014, the Company sold the Springfield gathering system located in East Texas to a third party.

San Juan  In April 2014, the Company sold the San Juan gathering system located in New Mexico, Colorado, and Utah along with the San Juan River gas processing plant located in New Mexico to a third party.

The following provides information regarding the Company’s midstream assets by geographic regions:
Area
 
Asset Type
 
Miles of
Gathering
Pipelines
 
Total
Horsepower
 
2014
Average Net
Throughput
(MMcf/d)
Rocky Mountains
 
Gathering, processing, and treating
 
11,900

 
1,244,100

 
3,800

Texas
 
Gathering, processing, and treating
 
3,600

 
248,400

 
1,100

Mid-Continent and other
 
Gathering
 
3,300

 
392,200

 
1,100

Total
 
 
 
18,800

 
1,884,700

 
6,000


MARKETING ACTIVITIES

The Company’s marketing segment actively manages Anadarko’s natural-gas, 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, oil, condensate, and NGLs are generally made at market prices for those products at the time of sale. The Company also purchases natural gas, oil, condensate, and NGLs from third parties, primarily near Anadarko’s production areas, to aggregate volumes so that the Company is positioned to fully use transportation, storage and fractionation capacity, 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, oil, condensate, and NGLs. The Company does not engage in market-making practices and limits its marketing activities to natural-gas, oil, NGLs, and LNG commodity contracts. The Company’s marketing-risk position is typically a net short position (reflecting agreements to sell natural gas, 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 oil reserves). See Commodity-Price Risk under Item 7A of this Form 10-K.


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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.

Oil, Condensate, and NGLs  Anadarko’s oil, condensate, and NGLs revenues are derived from production in the United States, Algeria, and Ghana. Most of the Company’s U.S. oil and NGLs production is sold under contracts with prices based on market indices, adjusted for location, quality, and transportation. Product from Algeria is sold by tanker as Saharan Blend, condensate, refrigerated propane, and refrigerated butane 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 Ghana is sold by tanker as Jubilee Oil to customers around the world. Jubilee Oil is high-quality crude that provides refiners large quantities of premium products such as gasoline, diesel, and jet fuel. Prior to the Company divesting its subsidiary in August 2014, oil from China was sold by tanker as Cao Fei Dian Blend to customers primarily in the Far East markets.

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 20—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 6,100 employees at December 31, 2014.

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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. 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 liability for removal costs and damages arising from an oil spill in waters of the United States
U.S. Department of the Interior 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, which imposes 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 implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories
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 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

These laws and 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. See Risk Factors under Item 1A of this Form 10-K for further discussion on hydraulic fracturing, ozone standards, climate change, including methane or other greenhouse gas emissions, and other regulations relating to environmental protection. 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.

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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. In addition, environmental laws and regulations, including those that may arise to address potential air and water impacts, 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.
The Company has reviewed its potential responsibilities under both OPA and CWA as they relate to the Deepwater Horizon events.
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. 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 condition, 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 federal 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 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.

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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 and capabilities include skimming vessels, barges, boom and dispersants, among others. 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.
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.
MSRC has equipment housed for the Atlantic Region, the Gulf of Mexico Region, the California Region, and the Pacific Northwest Region. Their equipment includes skimmers, 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 a 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.
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, 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. for assistance with Subsea Dispersant applications. 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 has an aircraft available for dispersant application or equipment transport. OSRL also has a number of active recovery boom systems, and a range of booms that can be used for offshore, nearshore, or shoreline responses. In addition, OSRL 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. OSRL also has a wide range of oiled wildlife equipment in conjunction with the Sea Alarm Foundation.
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.

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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, thorough title examinations of the drill site tract are 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,
2015
 
Position
R. A. Walker
 
57
 
Chairman, President and Chief Executive Officer
Robert P. Daniels
 
56
 
Executive Vice President, International and Deepwater Exploration
Robert G. Gwin
 
51
 
Executive Vice President, Finance and Chief Financial Officer
James J. Kleckner
 
57
 
Executive Vice President, International and Deepwater Operations
Charles A. Meloy
 
54
 
Executive Vice President, U.S. Onshore Exploration and Production
Robert K. Reeves
 
57
 
Executive Vice President, General Counsel and Chief Administrative Officer
M. Cathy Douglas
 
58
 
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.

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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 12, 2015, and hold office until their successors are duly elected and qualified. There are no family relationships between any directors or executive officers of Anadarko.

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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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include, among other things, 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 and sales volume 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 commercialization and transporting of natural gas, 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
processing volumes and pipeline throughput
general economic conditions, either nationally, internationally, or in the jurisdictions in which the Company or its subsidiaries are doing business
the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those necessary for drilling and/or development projects
legislative or regulatory changes, including changes relating to hydraulic fracturing; retroactive royalty or production tax regimes; 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

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the 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
the 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
civil or political unrest or acts of terrorism in a region or country
the 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 oil, NGLs, and condensate cargo shipping activities
physical, digital, internal, and external security breaches
supply and demand, technological, political, governmental, 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

RISK FACTORS

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. In addition, in September 2014, the U.S. District Court in New Orleans, Louisiana (Louisiana District Court) issued its Findings of Fact and Conclusions of Law in the first phase of the Deepwater Horizon trial. The Louisiana District Court found that BP is liable under general maritime law for the blowout, explosion, and oil spill and apportioned 67% of the fault to BP. BP is challenging certain of the Louisiana District Court’s findings.

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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 penalties and fines, 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. For example, daily settlement prices for New York Mercantile Exchange (NYMEX) West Texas Intermediate oil ranged from a high of $107.26 per barrel to a low of $53.27 per barrel during 2014. Daily settlement prices for NYMEX Henry Hub natural gas ranged from a high of $6.15 per million British thermal units (MMBtu) to a low of $2.89 per MMBtu during 2014. Our revenues, operating results, cash flows from operations, capital budget, 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 oil and natural-gas inventories
weather conditions
potential U.S. exports of liquefied natural gas, oil, condensate, or NGLs
ability of the members of the Organization of the 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
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 laws, 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

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reducing our revenues, operating income, or cash flows
reducing the amounts of our estimated proved oil, natural-gas, and NGLs 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, natural-gas, and NGLs 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. We may 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:
 
Ozone Standards. In December 2014, the U.S. Environmental Protection Agency (EPA) published proposed regulations to revise the National Ambient Air Quality Standard for ozone, recommending a standard between 65 to 70 parts per billion (ppb) for both the 8-hour primary and secondary standards protective of public health and public welfare. The current primary and secondary ozone standards are set at 75 ppb. The EPA is also taking comments on whether a 60 ppb standard should be established for the primary standard or whether the existing 75 ppb standard should be retained. If adopted, compliance with such regulations may require the Company to install new equipment to further control emissions and may also cause permitting delays. The EPA currently expects to issue a final rule by October 1, 2015.
Reduction of Methane Emissions. In January 2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will regulate methane emissions from the oil and gas sector. The Obama Administration seeks to reduce methane emissions from new and modified infrastructure and equipment in the oil and gas sector, including the drilling of new wells, by up to 45% from 2012 levels by 2025.
Climate Change. A number of state and regional efforts exist that are aimed at tracking or reducing greenhouse gas (GHG) emissions. In addition, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. 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 together with other criteria pollutants.
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.

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Changes in laws or regulations regarding hydraulic fracturing or other oil and gas operations could increase our costs of doing business, impose 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 oil from dense subsurface rock formations such as shales. 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 to fracture the surrounding rock and stimulate production.
Hydraulic fracturing is regulated by state oil and natural-gas commissions. However, several federal agencies have also asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards for the oil and gas industry; announced its intent to propose in early 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the Bureau of Land Management issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is expected to promulgate a final rule in early 2015. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the 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 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, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, or well-construction requirements on hydraulic-fracturing operations or prohibit these operations completely. 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, in exchange for the withdrawal of several initiatives relating to hydraulic fracturing and other oil and gas operations proposed for inclusion on the Colorado state ballot in November 2014, the governor of Colorado created the Task Force on State and Local Regulation of Oil and Gas Operations (Task Force) in September 2014 to make recommendations to the state legislature regarding the responsible development of Colorado’s oil and gas resources. Although it is early in the process, it is possible that, as a result of the Task Force’s recommendations, Colorado could adopt new policies or legislation relating to oil and natural-gas operations, including measures that would give local governments in Colorado greater authority to limit hydraulic fracturing and other oil and natural-gas operations or require greater distances between well sites and occupied structures. In the event state or local restrictions or prohibitions are adopted in areas where we conduct operations, such as the Wattenberg field in Colorado, 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 possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Such costs, delays, restrictions, or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
In addition to asserting regulatory authority, a number of federal entities are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. In April 2012, President Obama issued an executive order that established a working group for the purpose of coordinating policy, information sharing, and planning among federal agencies and offices regarding “unconventional natural-gas production,” including hydraulic fracturing. In December 2012, the EPA issued an initial progress report on a study begun in 2011 of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft final report expected to be issued for peer review and comment in early 2015. These studies and initiatives, or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur efforts to further regulate hydraulic fracturing.

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

Our total debt was $15.1 billion at December 31, 2014. 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 fully realize the value of our assets and opportunities 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 agreements governing our $3.0 billion five-year senior unsecured revolving credit facility and our $2.0 billion 364-day senior unsecured revolving credit facility contain a number of customary covenants, including a financial covenant requiring maintenance of a consolidated indebtedness to total capitalization ratio of no greater than 65%, and limitations on certain secured indebtedness, sale-and-leaseback transactions, and mergers and other fundamental changes. Our ability to meet such covenants may be affected by events beyond our control.

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

As of December 31, 2014, our long-term debt was rated “BBB” with a stable outlook by Standard and Poor’s (S&P), “BBB-” with a positive outlook by Fitch Ratings (Fitch), and “Baa3” with a positive outlook by Moody’s Investors Service (Moody’s). In February 2015, Moody’s raised our long-term debt rating to “Baa2” and changed the outlook to stable. Although we are not aware of any current plans of S&P, Fitch, or Moody’s to lower their respective ratings on our debt, we cannot be assured that our credit ratings will not be downgraded. A downgrade in our credit ratings could negatively impact our cost of capital or our ability to effectively execute aspects of our strategy. If our credit ratings were downgraded, it could affect our ability to raise debt in the public debt markets and the cost of that new debt could be much higher than our outstanding debt. In addition, a downgrade could affect the Company’s requirements to provide financial assurance of its performance under certain contractual arrangements and derivative agreements. See Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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

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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 the average beginning-of-month prices during the 12-month period for the respective year. 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.

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.

Future 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, and uncertainties with regard to European sovereign debt, have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. Continued concerns could cause demand for petroleum products to diminish or stagnate, which could impact the price at which we can sell our oil, natural gas, and NGLs; affect the ability of our vendors, suppliers, and customers 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 $5.6 billion of goodwill on our Consolidated Balance Sheet at December 31, 2014. 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 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.

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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 our 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, such as the sage grouse, may negatively impact our operations. 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 Legal Proceedings under Item 3 and 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, Brazil, Colombia, Côte d’Ivoire, Kenya, Liberia, New Zealand, 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 and decommissioning activities 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.

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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.

Additional domestic and international deepwater drilling laws, regulations, and other restrictions; delays in the processing and approval of drilling permits and exploration and oil spill-response plans; and other related developments 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, imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these new and more stringent rules and regulations, in addition to 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, 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 supplemental bonding and costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities. If similar material spill 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. 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.

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, Colombia, Côte d’Ivoire, Ghana, Kenya, Liberia, Mozambique, and New Zealand. 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

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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 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 developing the TEN complex. In the event Côte d’Ivoire is successful in its maritime border claims, this development could be materially impacted. Also, Venezuela and Guyana are in a dispute regarding their maritime and land borders in which the two countries have initiated a dialogue. We are unable to ascertain the full impact of this border dispute on future operations in Guyana.
Outbreaks of civil and political unrest and acts of terrorism have occurred in countries in Europe, Africa, and the Middle East, including countries where we conduct operations. 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, directly or indirectly, by laws, policies, and regulations of the United States affecting foreign trade and taxation, including U.S. trade sanctions.
Realization of any of the factors listed above could materially and adversely affect the Company’s financial condition, results of operations, or cash flows.

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, natural-gas, or NGLs 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, requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market including swap clearing and trade execution requirements. While many rules and regulations have been promulgated and are already in effect, other rules and regulations, including the proposed margin rules, position limits, and commodity clearing requirements, remain to be finalized or effectuated, and therefore, the impact of those rules and regulations on us is uncertain at this time.

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New or modified rules, regulations, or legal requirements may increase the cost and impact the availability to our counterparties of their hedging and swap positions that they can make available to us, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to separate entities, which may not be as creditworthy as the current counterparties. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation or post margin collateral. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.
The Dodd-Frank Act, and the rules promulgated thereunder, could (i) significantly increase the cost, or decrease the liquidity, of energy-related derivatives we use to hedge against commodity-price fluctuations (including through requirements to post collateral), (ii) materially alter the terms of derivative contracts, (iii) reduce the availability of derivatives to protect against risks we encounter, and (iv) increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and applicable rules and regulations, our cash flow may become more volatile and less predictable, which could adversely affect our 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.

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/loss of 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 financial condition, results of operations, or cash flows.

40


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 qualified personnel
civil and political environment of, and existing infrastructure in, 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.

41


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, lead to unexpected future costs, or adversely affect the timing of activities.

Our ability to sell our oil, natural gas, and NGLs 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, natural gas, and NGLs, which could increase our costs and/or reduce the revenues we might obtain from the sale of the oil and gas.

42


Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

As an oil and gas producer, we face various security threats, including cybersecurity threats such as attempts to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities, and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data, which could have an adverse effect on our reputation, financial condition, results of operations, or cash flows.
While we have experienced cybersecurity attacks, we have not suffered any material losses relating to such attacks; however, there is no assurance that we will not suffer such losses in the future. In addition, as cybersecurity threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate or remediate any cybersecurity vulnerabilities.

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.

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.

43


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 the resolution of pending proceedings will not have a material adverse effect on the Company’s financial condition, results of operations, or cash flows.
In September 2013, Anadarko received a Notice of Proposed Penalty Assessment 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, BSEE alleged several violations of certain offshore operational requirements. Anadarko disputed many of the allegations and in October 2014 received a Revised Final Reviewing Officer’s Decision from BSEE for a penalty of $70,000.
In June 2014, the EPA alleged that Anadarko was not in compliance with a consent decree entered into by the U.S. District Court for the District of Colorado on March 27, 2008 to resolve certain Clean Air Act violations in Colorado and Utah. Specifically, the EPA alleged violations of the consent decree at three of Anadarko’s compressor station facilities located in Utah. In November 2014, Anadarko entered into a joint stipulation with the EPA and agreed to pay a penalty of $599,000.
WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the EPA concerning enforcement for alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Granger, Wyoming facilities. Although management cannot predict the outcome of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.
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.

44


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 30, 2015, there were approximately 11,400 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 2014 and 2013:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2014
 
 
 
 
 
 
 
Market Price
 
 
 
 
 
 
 
High
$
86.86

 
$
112.06

 
$
113.51

 
$
102.68

Low
$
77.80

 
$
84.54

 
$
100.40

 
$
71.00

Dividends
$
0.18

 
$
0.27

 
$
0.27

 
$
0.27

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


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.

45


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, 2014:
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
 
6,791,018

 
$
69.96

 
21,169,470

Equity compensation plans not
   approved by security holders
 

 

 

Total
 
6,791,018

 
$
69.96

 
21,169,470


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 2014:
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
 
14,821

 
$
92.69

 

 
 
November
 
79,151

 
$
92.83

 

 
 
December
 
2,084

 
$
77.60

 

 
 
Fourth Quarter 2014
 
96,056

 
$
92.48

 

 
$

 _______________________________________________________________________________
(1) 
During the fourth quarter of 2014, 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.

46


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 a peer group of 11 companies. The companies included in the 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.

Comparison of 5-Year Cumulative Total Return Among
Anadarko Petroleum Corporation, the S&P 500 Index, and a Peer Group
Copyright© 2015 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 the peer group on December 31, 2009, and its relative performance is tracked through December 31, 2014. 
Fiscal Year Ended December 31
2009
 
2010
 
2011
 
2012
 
2013
 
2014
Anadarko Petroleum Corporation
$
100.00

 
$
122.78

 
$
123.64

 
$
120.97

 
$
129.92

 
$
136.59

S&P 500
100.00

 
115.06

 
117.49

 
136.30

 
180.44

 
205.14

Peer Group
100.00

 
123.66

 
130.54

 
133.12

 
167.31

 
154.38


47


Item 6.  Selected Financial Data
 
Summary Financial Information (1)
millions except per-share amounts
2014
 
2013
 
2012
 
2011
 
2010
Sales Revenues
$
16,375

 
$
14,867

 
$
13,307

 
$
13,882

 
$
10,842

Gains (Losses) on Divestitures and Other, net
2,095

 
(286
)
 
104

 
85

 
142

Total Revenues and Other
18,470

 
14,581

 
13,411

 
13,967

 
10,984

Algeria Exceptional Profits Tax Settlement

 
33

 
(1,797
)
 

 

Deepwater Horizon Settlement and Related Costs
97

 
15

 
18

 
3,930

 
15

Operating Income (Loss)
5,403

 
3,333

 
3,727

 
(1,870
)
 
1,769

Tronox-related Contingent Loss
4,360

 
850

 
(250
)
 
250

 

Income (Loss)
(1,563
)
 
941

 
2,445

 
(2,568
)
 
821

Net Income (Loss) Attributable to Common Stockholders
(1,750
)
 
801

 
2,391

 
(2,649
)
 
761

Per Common Share (amounts attributable to common stockholders)
 
 
 
 
 
 
 
 
 
Net Income (Loss)—Basic
$
(3.47
)
 
$
1.58

 
$
4.76

 
$
(5.32
)
 
$
1.53

Net Income (Loss)—Diluted
$
(3.47
)
 
$
1.58

 
$
4.74

 
$
(5.32
)
 
$
1.52

Dividends
$
0.99

 
$
0.54

 
$
0.36

 
$
0.36

 
$
0.36

Average Number of Common Shares Outstanding—Basic
506

 
502

 
500

 
498

 
495

Average Number of Common Shares Outstanding—Diluted
506

 
505

 
502

 
498

 
497

Cash Provided by Operating Activities
8,466

 
8,888

 
8,339

 
2,505

 
5,247

Capital Expenditures
$
9,256

 
$
8,523

 
$
7,311

 
$
6,553

 
$
5,169

Current Portion of Long-term Debt
$

 
$
500

 
$

 
$
170

 
$
291

Long-term Debt
15,092

 
13,065

 
13,269

 
15,060

 
12,722

Total Debt
$
15,092

 
$
13,565

 
$
13,269

 
$
15,230

 
$
13,013

Total Stockholders’ Equity
19,725

 
21,857

 
20,629

 
18,105

 
20,684

Total Assets
$
61,689

 
$
55,781

 
$
52,589

 
$
51,779

 
$
51,559

Annual Sales Volumes
 
 
 
 
 
 
 
 
 
Natural Gas (Bcf)
945

 
968

 
913

 
852

 
829

Oil and Condensate (MMBbls)
106

 
91

 
86

 
79

 
74

Natural Gas Liquids (MMBbls)
44

 
33

 
30

 
27

 
23

Total (MMBOE)(2)
308

 
285

 
268

 
248

 
235

Average Daily Sales Volumes
 
 
 
 
 
 
 
 
 
Natural Gas (MMcf/d)
2,589

 
2,652

 
2,495

 
2,334

 
2,272

Oil and Condensate (MBbls/d)
292

 
248

 
233

 
217

 
201

Natural Gas Liquids (MBbls/d)
119

 
91

 
83

 
74

 
63

Total (MBOE/d)
843

 
781

 
732

 
680

 
643

Proved Reserves
 
 
 
 
 
 
 
 
 
Natural-gas Reserves (Tcf)
8.7

 
9.2

 
8.3

 
8.4

 
8.1

Oil and Condensate Reserves (MMBbls)
929

 
851

 
767

 
771

 
749

Natural-gas Liquids Reserves (MMBbls)
479

 
407

 
405

 
374

 
320

Total Proved Reserves (MMBOE)
2,858

 
2,792

 
2,560

 
2,539

 
2,422

Number of Employees
6,100

 
5,700

 
5,200

 
4,800

 
4,400

(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
 
 

48


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 2014. The Company increased sales volumes per day by approximately 8% over 2013 and added 502 million barrels of oil equivalent (MMBOE) of proved reserves. The Company ended 2014 with $7.4 billion of cash on hand, full 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.
In January 2015, the Company paid $5.2 billion after the settlement agreement resolving all claims asserted in the Tronox Adversary Proceeding became effective and replaced the $5.0 billion Facility with two new unsecured credit facilities. The Company paid the settlement using cash on hand and borrowings. 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
identify and commercialize resources
employ a global business development approach
ensure financial discipline and flexibility

Exploring in high-potential, proven, and emerging basins worldwide provides the Company with growth opportunities. Anadarko’s exploration success has created value by increasing future resource potential, while providing the flexibility to mitigate risk by monetizing discoveries.
Developing a portfolio of primarily unconventional resources provides the Company a stable base of capital-efficient and predictable development opportunities that, in turn, positions the Company for consistent growth at competitive rates.
Anadarko’s global business development approach transfers core skills across the globe to assist in the discovery and development of world-class resources that are accretive to the Company’s performance. These resources help form an optimized global portfolio where both surface and subsurface risks are actively managed.
A strong balance sheet is essential for the development of the Company’s assets, and Anadarko is committed to disciplined investment in its businesses to efficiently manage commodity price cycles. Maintaining financial discipline enables the Company to capitalize on the opportunities afforded by its global portfolio, while allowing the Company to pursue new strategic growth opportunities.

49


Significant 2014 operating and financial activities include the following:

Overall