10-K 1 apc201510k-10k.htm 10-K 10-K
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, 2015
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)
 
(Zip Code)
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
7.50% Tangible Equity Units
 
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, 2015, was $39.6 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 February 5, 2016, is shown below:
Title of Class
  
Number of Shares Outstanding
Common Stock, par value $0.10 per share
  
508,438,647
Documents Incorporated By Reference
Portions of the Definitive Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 10, 2016 (to be filed with the Securities and Exchange Commission prior to March 31, 2016), 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 2.1 billion barrels of oil equivalent (BOE) of proved reserves at December 31, 2015. 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, 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 Algeria, Ghana, Mozambique, Colombia, Côte d’Ivoire, New Zealand, Kenya, 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 separately managed 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 oil, condensate, natural gas, and natural gas liquids (NGLs) and plans for the development and operation of the Company’s liquefied natural gas (LNG) project in Mozambique.

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 oil, natural gas, 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 U.S. Securities and Exchange Commission (SEC). Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on its website located at www.investors.anadarko.com/sec-filings. 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 Form 10-K, or any other filing, please contact Anadarko Petroleum Corporation, Investor Relations, P.O. Box 1330, Houston, Texas 77251-1330, 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 Reference Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Anadarko, that file electronically with the SEC.

Operating Outlook  During 2015, the oil and natural-gas industry experienced a significant decrease in commodity prices driven by a global supply/demand imbalance for oil and an oversupply of natural gas in the United States. The decline in commodity prices and global economic conditions have continued into 2016, and low commodity prices may exist for an extended period.
The Company plans to continue its disciplined and focused approach in 2016 by emphasizing value over growth, enhancing operational efficiencies, reducing capital expenses, and managing its diverse asset portfolio. Management has recommended to the Board of Directors (Board) a 2016 capital budget of approximately $2.8 billion, which excludes the capital budget of Western Gas Partners, LP (WES), a publicly traded consolidated subsidiary. The $2.8 billion budget is nearly 50% lower than capital investments in 2015 and almost 70% lower than 2014.
The Company will continue to evaluate the oil and natural-gas price environments and may adjust its capital spending plans to maintain the appropriate liquidity and financial flexibility. Anadarko expects that its capital expenditures will be aligned with its cash flows from operations and targeted asset monetizations.


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OIL AND GAS PROPERTIES AND ACTIVITIES

The map below illustrates the locations of Anadarko’s significant 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 in the onshore Lower 48 states, deepwater Gulf of Mexico, and onshore Alaska. The Company’s U.S. operations accounted for 89% of sales volumes and 80% of sales revenues during 2015, and 90% of proved reserves at year-end 2015.

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 11,000 wells and owns interests in approximately 4,000 nonoperated wells. Anadarko operates fractured-carbonate/shale reservoirs and tight-gas assets within the region. The Company also has fee ownership of mineral rights under approximately eight million acres that pass through Colorado and 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, 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.
In 2015, activities in the Rockies primarily focused on production and adding reserves through horizontal drilling, infill drilling, and optimizing both wellbore and completion design. In addition, a major emphasis was placed on reducing capital and operating expenses and increasing efficiencies to enhance margins. In 2015, Rockies liquids sales volumes increased by 11% over 2014, equivalent to 17 thousand barrels of oil equivalent per day (MBOE/d), even with a reduction in sales volumes of 21 MBOE/d related to the impact of ethane rejection. The Company drilled 447 wells and completed 390 wells in the Rockies during 2015, primarily in the Wattenberg field, which is expected to be a focus area for Anadarko in 2016.

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Wattenberg  Anadarko operates approximately 5,000 vertical wells and 1,000 horizontal wells in the Wattenberg field. The field contains the Niobrara and Codell formations, which are naturally fractured formations that hold both liquids and natural gas. During 2015, the Company’s drilling program focused entirely on horizontal development, drilling 365 horizontal wells. Sales volumes in the field increased 32% compared to 2014, with increases of 29% in oil volumes and 27% in total liquids volumes. Horizontal drilling results in the field continue to be strong, with economics that are enhanced by the Company’s ownership of the Land Grant mineral interest, a consolidated core acreage position, and recent enhancements to the operated and controlled infrastructure and takeaway capacity.
Drilling spud-to-rig-release cycle time improved from 10.5 days in 2014 to 6.3 days in 2015. The full-year 2015 average drilling cost per foot was reduced by approximately 40% and completion capital was reduced by 32% relative to 2014. Operated well capital costs in 2015 have decreased to less than $3.5 million from $4.0 million in 2014 for an equivalent well, driven by continued operational efficiencies and supply-chain savings. During 2015, Anadarko intentionally deferred completions in order to focus on preserving value by decreasing capital investments in a lower commodity-price environment and to provide additional production flexibility for 2016.
In 2015, the second cryogenic processing train at the Lancaster plant was placed into service, resulting in an additional 300 million cubic feet per day (MMcf/d) of processing capacity and a field-wide increase in NGLs recoveries. The Company made substantial progress toward completion of its centralized oil stabilization facility (COSF) in 2015 and expects to commission the facility in early 2016. The COSF will increase oil recoveries, enhance efficiencies of tank batteries, lower operating expenses, and further reduce impacts on the environment. Anadarko added 180 MMcf/d of field compression in 2015, which reduced gathering system pressures in the field, enhancing system efficiency and improving the base production profile.

Greater Natural Buttes  The Greater Natural Buttes area in eastern Utah is one of the Company’s major tight-gas assets. The Company uses cryogenic processing facilities in this area to extract NGLs from the natural-gas stream. The Company operates approximately 2,900 wells in the area and drilled 60 wells in 2015. Average drilling cost per foot was reduced by 10% and completion capital was reduced by 23% relative to 2014. The Company operated the field at a reduced activity level for the majority of 2015 due to capital being diverted to higher-margin projects.

Powder River Deep  The Company drilled a three-well exploration/appraisal program targeting the Turner formation, where the Company has previously seen strong results. Additionally, a farm-out agreement was reached during the first quarter of 2015, whereby Anadarko may be carried in at least three deep horizontal tests to further evaluate multiple oil objectives. The farm-in party has the option to earn up to 40,000 net acres of Anadarko’s position. The Company controls over 325,000 acres of deep mineral rights within the Powder River basin.

Laramie County  Anadarko holds ownership in more than 100,000 mineral-interest acres in this emerging liquids-rich play in the northern DJ basin in Wyoming. In 2015, the Company participated in more than 70 nonoperated wells testing the Niobrara and Codell formations. Results from 33 producing wells, 11 with first production in 2015, remain strong, with initial 30-day net production averaging approximately 1,000 barrels of oil equivalent per day (BOE/d).

Greater Green River Basin  Anadarko operates over 1,400 wells in the Wamsutter and Moxa fields. The Company also carries a nonoperated position in 2,600 wells across the two fields. Much of this producing area is located within the Land Grant, which enhances the Company’s economics in projects in the area. Anadarko reached a farm-out agreement in July 2015, whereby the Company will be fully carried on several exploration wells testing a liquids-rich opportunity located on the Land Grant.

Coalbed Methane Properties  During 2015, Anadarko sold its interest in its Powder River basin coalbed methane wells and related midstream assets for net proceeds of $154 million after closing adjustments.

Salt Creek and Monell  During 2015, Anadarko sold its interest in the Salt Creek and Monell enhanced oil recovery assets in Wyoming, with a sales price of $703 million, for net proceeds of $675 million after closing adjustments.


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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 Northern 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 2015, the Company continued to focus on improving its cost structure, delivering efficient production, and delineating its position in the Delaware basin. Activities in the region targeted continued drilling, completion and operational efficiencies, and process improvements and optimization, providing both lower costs and cycle-time improvements across the region. Compared with the prior year, capital expenditures were reduced in the region as the Company focused on higher-margin areas within the U.S. onshore to support future growth. Additional production flexibility for 2016 was provided by infrastructure expansions primarily in the Delaware basin, reductions in completion costs across the region, and the systematic buildup of intentionally deferred completions in the Eagleford shale and Delaware basin.
In 2015, liquids sales volumes in the region increased by 10%, although a decrease in gas sales volumes resulted in a total sales volume decrease of 5% from 2014. The Company drilled 338 operated horizontal wells and brought 318 wells online in 2015. In July 2015, Anadarko sold its interest in the Bossier natural-gas field and associated midstream assets in East Texas, with a sales price of $440 million, for net proceeds of $425 million after closing adjustments. In 2016, the Company expects to continue its horizontal drilling program, focusing on the Delaware basin.

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Delaware Basin  Anadarko holds interests in over 600,000 gross acres in the Delaware basin. Anadarko’s 2015 drilling activity primarily targeted the Wolfcamp shale play, liquids-rich Bone Spring 2 tight sands, and the Avalon shale play. In 2015, Anadarko drilled 80 operated wells and participated in 49 nonoperated wells. Significant infrastructure continues to be added to facilitate future growth from this asset. At year-end 2015, the Company had six operated rigs drilling in the Wolfcamp shale.
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 for increased efficiency, including multi-well pads, extended laterals, and horizontal-well spacing. The Company has identified thousands of potential drilling locations in the Wolfcamp formation that are expected to provide substantial opportunity for Anadarko’s future activity in the basin.

Eagleford  The Eagleford shale development in South Texas consists of approximately 346,000 gross acres and over 1,300 producing wells. In 2015, the Company averaged 4 drilling rigs, drilled 183 wells, completed 179 wells, and brought 201 wells online, generating sales volume growth of 20% over 2014. In 2015, Anadarko continued to recognize improvements in Eagleford shale drilling efficiency, translating to record-low average cost per foot, while increasing average lateral length. Anadarko completed five successful tests targeting the mid and upper Eagleford shale zones and intends to test for additional reserves across its acreage position. The Company also continued to optimize other development parameters such as completions design, spacing, and choke management.

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 2015, Anadarko continued to delineate and develop this acreage by drilling 24 operated horizontal wells with a one-rig program. Under a carried-interest arrangement entered into in 2014, which requires a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development, Anadarko has generated positive cash flow in an unfavorable commodity-price environment while testing new concepts and opportunities. At December 31, 2015, $111 million of the total $442 million carry obligation had been funded.

East Texas/North Louisiana  Anadarko holds 223,000 gross acres in East Texas/North Louisiana. Anadarko continued its capital program in the East Texas/North Louisiana area in 2015, targeting the liquids-rich Haynesville shale in East Texas and the prolific dry-gas Haynesville shale in North Louisiana. In 2015, Anadarko averaged 3.5 operated rigs and drilled 39 wells in the Haynesville and Cotton Valley formations.

Marcellus  The Company holds 625,000 gross acres in the Marcellus shale of the Appalachian basin. In 2015, 1 operated horizontal well was drilled and Anadarko participated in the drilling of 18 nonoperated horizontal wells. The Company’s sales volumes in the Marcellus shale decreased in 2015 as the Company reduced its investment and production in the area in response to the lower commodity-price environment and ongoing third-party pipeline infrastructure maintenance.

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Gulf of Mexico  Anadarko owns an average working interest of 60% in 279 blocks in the Gulf of Mexico. The Company operates eight active floating platforms and holds interests in 34 fields. During 2015, 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 existing infrastructure to cost-effectively develop known resources.

Development
Lucius  The Company realized first production at the Anadarko-operated Lucius Spar in January 2015, bringing on six wells throughout the early part of 2015. The Lucius project was developed with production startup only three years from sanction and five years from discovery. The 80-thousand barrels per day (MBbls/d) spar is located in Keathley Canyon Block 875 at a water depth of 7,000 feet. The Company has realized steady production performance at nameplate capacity since May 2015. Anadarko entered into a carried-interest arrangement with a third party in 2012. The $476 million carry commitment was fully funded in 2014 and covered a substantial majority of Anadarko’s capital costs through first production. Following the carried-interest arrangement and 2014 equity re-determination, the Company holds a 23.8% working interest in Lucius.

Heidelberg  During 2015, the Company continued to advance the Anadarko-operated Heidelberg development project, which was sanctioned during the second quarter of 2013. Installation of the Lucius-lookalike spar was completed and first oil was realized in January 2016, three months ahead of schedule. Three wells are ready for production and are expected to be brought online during the first quarter of 2016, while an additional two wells are expected to be drilled later in 2016.
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. At December 31, 2015, $793 million of the $860 million carry obligation had been funded. Anadarko holds a 31.5% working interest in Heidelberg.


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Caesar/Tonga  At Caesar/Tonga (33.75% working interest), the Company successfully completed a fifth development well (GC 683#2) in the first quarter of 2015. Anadarko has recently completed a sixth development well (GC 683#3), which is expected to come online later in the first quarter of 2016. A seventh well (GC 726#2) reached total depth in January 2016 and encountered over 250 net feet of oil pay. The well is currently being completed. Due to the continued success at Caesar/Tonga, the Company sanctioned a Phase 2 development plan during the fourth quarter of 2015 and anticipates first oil in the fourth quarter of 2017.

Constitution  At Constitution (100% working interest), the Company executed a successful platform drilling program in 2015, where the A4 well was sidetracked, completed, and brought online.

K2 Complex  At K2 (41.8% working interest), the GC 562#5 infill well, which found 210 net feet of oil pay in the Miocene, was successfully completed. The GC 561#3 development well found 331 net feet of oil pay in the M9, M10, and M15 sands and is currently being completed. First production is anticipated by the second quarter of 2016.

Independence Hub Gas Complex  The last producing well at Independence Hub (IHUB) watered out in December 2015. IHUB was a tremendous asset for the Company with cumulative gross production of 1.3 trillion cubic feet of natural gas in eight and a half years. Plans to plug and abandon the remaining IHUB wellbores and decommission the facilities are underway.

Exploration
Two nonoperated exploration wells were drilled in the Gulf of Mexico during 2015. The Yeti exploration well (37.5% working interest) targeted a sub-salt Miocene-aged three-way closure in Walker Ridge and encountered more than 270 net feet of oil pay. The Yeti discovery is located in approximately 5,900 feet of water, approximately 20 miles south of Anadarko’s operated Heidelberg field. The Thorvald exploration well (50% working interest), located in approximately 4,800 feet of water in southern Mississippi Canyon, tested multiple sub-salt Miocene reservoirs in a three-way closure and encountered approximately 80 net feet of oil pay.

Appraisal
Shenandoah  The Company spud the Shenandoah-4 well, the third appraisal well at the Shenandoah discovery (30% working interest), in the second quarter of 2015. The well tested the up-dip extent of the basin. The subsequent Shenandoah-4 sidetrack encountered more than 620 net feet of oil pay, extending the lowest known oil column down-dip. Following the success of the Shenandoah-4 sidetrack, the Company and its partners successfully acquired more than 550 feet of whole-core from the hydrocarbon-bearing reservoir interval.

Yeti  The Yeti discovery well was successfully sidetracked to test the down-dip limits of the field. The Yeti-3 appraisal well finished drilling during the fourth quarter of 2015 and was successful in acquiring more than 320 feet of whole-core across the primary Miocene-aged reservoir intervals encountered in the Yeti discovery well. The Company and its partners are currently evaluating potential development options for the Yeti 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 33-well extension of the Alpine field. Drilling at Alpine West commenced in 2015, with four out of seven producing wells coming online during the fourth quarter of 2015 at a combined rate of 20 MBbls/d.
The Greater Mooses Tooth 1 (GMT1) project was sanctioned in November 2015 and will become the next satellite development west of the Alpine field. First production at GMT1 is expected in 2018.

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International

Overview  Anadarko’s international operations include oil, natural-gas, and NGLs production and development in Algeria and Ghana, along with activities in Mozambique where the Company continues to make progress towards a final investment decision on an LNG development. The Company also has exploration acreage in Colombia, Côte d’Ivoire, Mozambique, New Zealand, Kenya, and other countries. International locations accounted for 11% of Anadarko’s sales volumes and 20% of sales revenues during 2015, and 10% of proved reserves at year-end 2015. In 2016, the Company expects to focus its exploration and appraisal activity in Côte d’Ivoire and Colombia.

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 368 MBbls/d in 2015, and the cumulative gross production from all three facilities reached a significant milestone, surpassing 2.0 billion BOE in July 2015. The Company drilled seven development wells in 2015.

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 103 MBbls/d of oil in 2015. Natural-gas exports commenced in the fourth quarter of 2014, and in 2015, an average of 66 MMcf/d was exported from the Jubilee field to an onshore gas processing plant in satisfaction of a commitment established in conjunction with the Jubilee development plan. In 2015, development continued with the J-24 well completed as an oil producer; the J-37 well drilled, completed, and put on production; and the J-36 well drilled with completion planned for 2016. Following the appraisal work completed in 2014, the Mahogany and Teak fields were declared commercial in March 2015, and a full-field development plan for the Greater Jubilee Area was submitted to the government of Ghana in December 2015. At this time, options to further increase the oil and gas throughput capacity of the floating production, storage, and offloading vessel (FPSO) are under evaluation.
The Tweneboa/Enyenra/Ntomme (TEN) project (19% nonoperated working interest) is located in the Deepwater Tano Block. Significant progress was made during 2015, including completing mechanical work on the FPSO, drilling the eleventh well, and completing four of the wells in preparation for first oil. The TEN project will use an 80-MBbls/d-capacity FPSO for production from subsea wells. The project, which commenced in 2013, was more than 80% complete at year-end 2015 and remains on budget and on schedule for first production in the third quarter of 2016.

Mozambique  Anadarko operates Offshore Area 1 (26.5% working interest), which totals approximately 1.2 million gross acres. The Company is progressing three elements that will position the project for execution and deliver future value: the legal and contractual framework to develop LNG in Mozambique; project finance; and long-term LNG sales contracts.

Development  During the first half of 2015, the Company successfully executed a six-well drilling campaign in the Golfinho-Atum field. Following this campaign, an independent third party completed a resource certification for sufficient volumes from Golfinho-Atum to support the initial development of two LNG trains. Anadarko continues to work with the construction and installation contractors for opportunities to reduce execution risk once the project progresses to the construction phase. Anadarko and its partners continue to progress over eight million metric tonnes per annum of LNG offtake to long-term sales contracts. The July 2015 ratification of the Decree Law that was published by the Mozambique government in 2014 was a significant milestone in the establishment of a project-wide legal and contractual framework. During the fourth quarter of 2015, Anadarko and its partners executed a Unitization and Unit Operating Agreement with Offshore Area 4 partners that covers the joint development of the straddling Prosperidade (Offshore Area 1) and Mamba (Offshore Area 4) reservoir. The agreement is subject to government approval.


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Exploration  In Offshore Area 1, the Company completed drilling and evaluation operations at the Tubarão Tigre-2 appraisal well during the first quarter of 2015. The well successfully appraised the Tubarão Tigre discovery that was drilled in 2014.
In Onshore Rovuma (35.7% working interest), the Company completed drilling and evaluation operations at the Kifaru-1 well during the first quarter of 2015. The well did not encounter hydrocarbons and was plugged and abandoned.

Colombia  Anadarko controls the exclusive rights to explore or conduct technical evaluation activities on nine blocks totaling approximately 16 million gross acres. The COL 1, COL 2, COL 6, and COL 7 blocks are operated at a 100% working interest and the remaining blocks are operated at a 50% working interest.
During 2015, Anadarko spud two exploration wells. The Kronos-1 (50% working interest) discovery encountered 130 to 230 net feet of natural-gas pay in the upper objective, proving the presence of a working petroleum system and validating the geologic and seismic interpretations. The well finished drilling during the third quarter of 2015 after testing a deeper objective where it encountered non-commercial hydrocarbons. Anadarko and its partner are evaluating the drilling results to determine the next steps. The Calasu-1 well (50% working interest) tested a large four-way structure located approximately 100 miles north of the Company’s Kronos discovery. The well finished drilling during the fourth quarter of 2015 and encountered non-commercial quantities of pay.

Côte d’Ivoire  Anadarko owns an operated working interest in four offshore blocks totaling approximately 1.0 million gross acres, including CI-103 with a 65% working interest and CI-527, CI-528, and CI-529, each with a 90% working interest. During the third quarter of 2015, Anadarko acquired the CI-527 block, which is contiguous with the CI-103 block to the northwest and the CI-528 block to the south. Planning is underway for a two-well exploration program on the CI-527 and CI-528 blocks in 2016.
A drilling and interference testing program began during the first quarter of 2016 as part of the continued appraisal of the Paon discovery (CI-103). The program will also include additional appraisal drilling. The data from these operations are expected to provide insight on reservoir connectivity, deliverability, fluid properties, and reservoir size.

New Zealand  Anadarko controls the exclusive rights to explore or conduct technical evaluation activities on four blocks totaling approximately 42 million gross acres, of which 6.1 million gross acres are owned under exploration licenses. Anadarko owns an operated 45% working interest in the Canterbury basin block and an operated 100% working interest in two Pegasus basin blocks. In the 36 million acre New Caledonia basin block, Anadarko has a 25% nonoperated working interest. During 2015, the Company acquired a 3D seismic survey in the Canterbury basin and is currently evaluating potential future exploration opportunities.

Kenya  Anadarko owns an operated 45% working interest in three offshore deepwater blocks, encompassing approximately 3.7 million gross acres. The Company is evaluating potential future exploration opportunities.

Other  Anadarko holds exploration interests in approximately 300,000 gross acres in two offshore blocks located in the Campos basin of Brazil. Anadarko also has exploration opportunities 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. For 2015, the International geographic area consisted of proved reserves located in Algeria and Ghana, which by country and in total represented less than 15% of the Company’s total proved reserves. The Company sold its Chinese subsidiary in 2014.

Summary of Proved Reserves
 
Oil and
Condensate
(MMBbls)
 
Natural Gas
(Bcf)
 
NGLs
(MMBbls)
 
Total
(MMBOE)
December 31, 2015
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
332

 
5,184

 
257

 
1,453

International
159

 
30

 
15

 
179

Undeveloped
 
 
 
 
 
 
 
United States
193

 
807

 
68

 
396

International
29

 

 

 
29

Total proved
713

 
6,021

 
340

 
2,057

 
 
 
 
 
 
 
 
December 31, 2014
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
352

 
6,635

 
304

 
1,762

International
190

 
27

 
13

 
207

Undeveloped
 
 
 
 
 
 
 
United States
352

 
2,033

 
162

 
853

International
35

 
4

 

 
36

Total proved
929

 
8,699

 
479

 
2,858

 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
347

 
7,120

 
268

 
1,801

International
202

 

 

 
202

Undeveloped
 
 
 
 
 
 
 
United States
245

 
2,085

 
127

 
720

International
57

 

 
12

 
69

Total proved
851

 
9,205

 
407

 
2,792


The Company’s proved reserves product mix increased to 52% liquids in 2015, compared to 49% in 2014 and 45% in 2013. The Company’s year-end 2015 proved reserves product mix was 35% oil and condensate, 48% natural gas, and 17% NGLs.

13


Changes to the Company’s proved reserves during 2015 are summarized in the table below:
MMBOE
2015
 
2014
 
2013
Proved Reserves
 
 
 
 
 
January 1
2,858

 
2,792

 
2,560

Reserves additions and revisions
 
 
 
 
 
Discoveries and extensions
29

 
63

 
145

Infill-drilling additions (1)
89

 
577

 
410

Drilling-related reserves additions and revisions
118

 
640

 
555

Other non-price-related revisions (1)
289

 
(137
)
 
(40
)
Net organic reserves additions
407

 
503

 
515

Acquisition of proved reserves in place
1

 

 
36

Price-related revisions (1)
(624
)
 
(1
)
 
(23
)
Total reserves additions and revisions
(216
)
 
502

 
528

Sales in place
(279
)
 
(124
)
 
(12
)
Production
(306
)
 
(312
)
 
(284
)
December 31
2,057

 
2,858

 
2,792

Proved Developed Reserves
 
 
 
 
 
January 1
1,969

 
2,003

 
1,883

December 31
1,632

 
1,969

 
2,003

_______________________________________________________________________________
(1) 
Combined and reported as revisions of prior estimates in the Company’s Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information) under Item 8 of this Form 10-K. Reserves related to infill-drilling additions are treated as positive revisions. Price-related revisions reflect the impact of current prices on the reserves balance at the beginning of 2015. Other non-price-related revisions are primarily a reflection of performance improvements coupled with the benefit of reduced year-end costs.

Proved reserves are estimated based on the average beginning-of-month prices during the 12-month period for the respective year. The average prices used to compute proved reserves at December 31, 2015, were $50.28 per barrel (Bbl) for oil, $2.59 per million British thermal units for gas, and $19.47 per Bbl for NGLs. Prices for oil, natural gas, and NGLs can fluctuate widely. If commodity prices remain below the average prices used to estimate 2015 proved reserves, the Company would expect additional negative price-related reserves revisions in 2016, which could be significant.
The Company’s estimates of proved developed reserves, proved undeveloped reserves (PUDs), and total proved reserves at December 31, 2015, 2014, and 2013, and changes in proved reserves during the last three years are presented in the 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, 2015. 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 during 2015 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 PUD development within five years unless specific circumstances warrant a longer development time horizon.
MMBOE
 
PUDs at January 1, 2015
889

Revisions of prior estimates
(199
)
Extensions, discoveries, and other additions
12

Conversions to developed
(236
)
Sales
(41
)
PUDs at December 31, 2015
425


Revisions  In 2015, PUD reserves were revised downward by 199 MMBOE. Negative revisions of 419 MMBOE were due to the decline in commodity prices and include a reduction to NGLs reserves of 22 MMBOE associated with price-induced ethane rejection. The negative price-related revisions were partially offset by a net increase of 220 MMBOE driven by increases from improved economics associated with performance improvements coupled with reduced year-end costs, increases from successful infill drilling mainly in the Wattenberg area of the Rockies, and decreases primarily associated with updates to development plans to align with the current economic environment.

Extensions, Discoveries, and Other Additions During 2015, Anadarko added 12 MMBOE of PUDs through the extension of proved acreage, primarily as a result of successful drilling in the Wolfcamp shale play in the Southern and Appalachia Region.

Conversions  In 2015, the Company converted 236 MMBOE of PUD reserves to developed status, equating to 36% of total year-end 2014 PUDs when adjusted for revisions and sales. Approximately 81% of PUD conversions occurred in U.S. onshore assets, 17% occurred in Gulf of Mexico assets, and the remaining 2% occurred in international assets.
In 2015, onshore development activity in the U.S. resulted in the conversion of 126 MMBOE in the Rockies, 61 MMBOE in the Southern and Appalachia Region, and 5 MMBOE in Alaska. An additional 40 MMBOE were converted in various Gulf of Mexico fields. The remaining PUD conversions in 2015 were associated with ongoing development of international assets.
Anadarko spent $2.4 billion to develop PUDs in 2015, of which approximately 75% related to U.S. onshore assets, 13% related to international assets, and 12% related to Gulf of Mexico assets.

Sales  In 2015, PUD reserves decreased by 41 MMBOE due to asset sales, primarily associated with the Company’s divestiture activities in the Rockies.

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 associated with arctic development, deepwater development, and international programs may take longer.
At December 31, 2015, the Company had 10 MMBOE of pre-2011 PUDs that remained undeveloped. Approximately two-thirds of these PUDs are associated with Gulf of Mexico opportunities that have been drilled and are scheduled for completion in 2016. The remaining pre-2011 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 of the fields were brought online and the facility became fully operational.


15


Technologies Used in Proved Reserves Estimation  The Company’s 2015 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 meets with management, members of the CRG, and the Company’s independent petroleum consultants, Miller and Lents, Ltd. (M&L), to discuss the results of procedures and methods reviews as discussed below as well as other matters and policies related to reserves.
The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserves estimates, has over 29 years of experience in the oil and gas industry, including over 15 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 29 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, 2015. 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 14 fields that included major assets in the United States and Africa and encompassed approximately 86% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, 2015. 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.

16


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.

Sales Volumes, Prices, and Production Costs

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)
 
Oil and
Condensate
(MMBbls)
 
Natural
Gas
(Bcf)
 
NGLs
(MMBbls)
 
Barrels of
Oil
Equivalent
(MMBOE)
 
Oil and
Condensate
(Per Bbl)
 
Natural
Gas
(Per Mcf)
 
NGLs
(Per Bbl)
 
2015
 

 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Natural Buttes
1

 
126

 
4

 
26

 
$
38.23

 
$
2.00

 
$
14.84

 
$
10.70

Wattenberg
35

 
176

 
16

 
81

 
44.88

 
2.31

 
15.65

 
7.64

Other United States
49

 
550

 
25

 
165

 
45.19

 
2.45

 
18.33

 
8.51

Total United States
85

 
852

 
45

 
272

 
45.00

 
2.36

 
17.03

 
8.45

International
31

 

 
2

 
33

 
51.68

 

 
29.85

 
7.22

Total
116

 
852

 
47

 
305

 
46.79

 
2.36

 
17.61

 
8.31

2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Natural Buttes
1

 
154

 
4

 
31

 
$
81.74

 
$
3.93

 
$
39.16

 
$
10.30

Wattenberg
27

 
125

 
13

 
62

 
87.76

 
4.19

 
36.46

 
7.55

Other United States
46

 
666

 
26

 
182

 
88.29

 
4.08

 
34.29

 
9.07

Total United States
74

 
945

 
43

 
275

 
87.99

 
4.07

 
35.48

 
8.87

International
32

 

 
1

 
33

 
99.79

 

 
56.16

 
8.22

Total
106

 
945

 
44

 
308

 
91.58

 
4.07

 
36.01

 
8.80

2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Natural Buttes
1

 
168

 
4

 
33

 
$
87.46

 
$
3.12

 
$
41.79

 
$
9.59

Wattenberg
16

 
102

 
6

 
40

 
94.27

 
3.75

 
41.75

 
7.92

Other United States
41

 
698

 
23

 
179

 
98.38

 
3.56

 
36.14

 
8.64

Total United States
58

 
968

 
33

 
252

 
97.02

 
3.50

 
37.97

 
8.65

International
33

 

 

 
33

 
109.15

 

 

 
9.96

Total
91

 
968

 
33

 
285

 
101.41

 
3.50

 
37.97

 
8.80

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

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 22—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

17


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, 2015, Anadarko was contractually committed to deliver approximately 1,067 Bcf of natural gas to various customers in the United States through 2031. These contracts have various expiration dates, with approximately 33% of the Company’s current commitment to be delivered in 2016 and 79% by 2020. At December 31, 2015, Anadarko also was contractually committed to deliver approximately 12 MMBbls of oil to ports in Algeria and Ghana through 2016. 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, 2015:
 
Developed
Lease
 
Undeveloped
Lease
 
Fee Mineral
 
Total
thousands of acres
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Onshore
4,451

 
2,947

 
3,482

 
1,472

 
10,235

 
8,529

 
18,168

 
12,948

Offshore
270

 
132

 
1,362

 
866

 

 

 
1,632

 
998

Total United States
4,721

 
3,079

 
4,844

 
2,338

 
10,235

 
8,529

 
19,800

 
13,946

International
499

 
113

 
46,691

 
34,259

 

 

 
47,190

 
34,372

Total
5,220

 
3,192

 
51,535

 
36,597

 
10,235

 
8,529

 
66,990

 
48,318


At December 31, 2015, the Company had approximately four million net undeveloped lease acres scheduled to expire by December 31, 2016, 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 2015 drilling program focused on proven and emerging liquids-rich basins in the United States (onshore and deepwater Gulf of Mexico) and various international locations. Exploration activity in 2015 consisted of 28 gross completed wells, which included 22 U.S. onshore wells, 5 international wells, and 1 Gulf of Mexico well. Development activity in 2015 consisted of 902 gross completed wells, which included 892 U.S. onshore wells, 8 international wells, and 2 Gulf of Mexico wells.

18


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
 
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
16.0

 

 
16.0

 
573.1

 
13.8

 
586.9

 
602.9

International
2.4

 
0.4

 
2.8

 
1.8

 

 
1.8

 
4.6

Total
18.4

 
0.4

 
18.8

 
574.9

 
13.8

 
588.7

 
607.5

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


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, 2015:
 
Wells in the process
of drilling or
in active completion
 
Wells suspended or
waiting on completion (1)
 
Exploration
 
Development
 
Exploration
 
Development
United States
 
 
 
 
 
 
 
Gross
2

 
24

 
63

 
848

Net
0.7

 
12.6

 
26.1

 
548.3

International
 
 
 
 
 
 
 
Gross

 

 
62

 
29

Net

 

 
18.5

 
6.2

Total
 
 
 
 
 
 
 
Gross
2

 
24

 
125

 
877

Net
0.7

 
12.6

 
44.6

 
554.5

 _______________________________________________________________________________
(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.

19


Productive Wells

At December 31, 2015, the Company’s ownership interest in productive wells was as follows:
 
Oil Wells (1)
 
Gas Wells (1)
United States
 
 
 
Gross
3,898

 
20,518

Net
2,489.4

 
14,765.5

International
 
 
 
Gross
195

 
7

Net
34.5

 
1.7

Total
 
 
 
Gross
4,093

 
20,525

Net
2,523.9

 
14,767.2

________________________________________________________________
(1) 
Includes wells containing multiple completions as follows:
Gross
217

 
2,703

Net
189.2

 
2,290.0


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, a publicly traded consolidated subsidiary and limited partnership that acquires, owns, develops, and operates midstream assets. Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary, is a limited partnership that owns interests in WES. At December 31, 2015, Anadarko’s ownership interest in WGP consisted of an 87.3% limited partner interest and the entire non-economic general partner interest. At December 31, 2015, WGP’s ownership interest in WES consisted of a 34.6% limited partner interest, the entire 1.8% general partner interest, and all of the WES incentive distribution rights. At December 31, 2015, Anadarko also owned an 8.5% limited partner interest in WES through other subsidiaries.
At the end of 2015, Anadarko had 40 gathering systems and 54 processing and treating plants located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, Pennsylvania, and Texas. In 2015, the Company’s midstream activity was concentrated in liquids-rich growth areas such as Wattenberg, the Delaware basin, and the Eagleford shale, as well as in the Marcellus shale dry-gas play. In 2016, the Company expects its midstream investment to focus on the Delaware basin to build infrastructure for future Wolfcamp development.


20


Wattenberg  The Company placed into service a second 300-MMcf/d train at its Lancaster cryogenic processing plant. The plant supports 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 were placed online in 2015, which increased compression capacity by 180 MMcf/d. In addition, the Company neared completion of its COSF and will commission the facility in early 2016. The COSF, capable of handling 125 MBbls/d, will increase oil recoveries, enhance efficiencies of tank batteries, lower operating expenses, and further reduce impacts on the environment. Construction of the Saddlehorn pipeline, in which Anadarko has a 20% equity ownership, began in 2015. In November 2015, Saddlehorn Pipeline Company, LLC combined with Grand Mesa to form a single pipeline project, which enhances economics by reducing capital requirements. The combined pipeline, with an initial capacity of 340 MBbls/d, is planned to deliver various grades of oil from the DJ basin to storage facilities in Cushing, Oklahoma and is expected to be operational by mid-2016. Saddlehorn Pipeline Company, LLC will own an initial 190 MBbls/d of capacity with sole expansion rights. Also, the Company elected to participate in an expansion of the White Cliffs oil pipeline to increase the total capacity from 152 MBbls/d to approximately 215 MBbls/d. The expansion will be executed in stages throughout the first half of 2016. Management believes that Anadarko is well-positioned with its oil and NGLs transportation capacity, which includes transport by pipeline, rail, and truck.

Delaware Basin  In 2015, the Company expanded its midstream infrastructure for Bone Spring, Wolfcamp, and Avalon production in the Delaware basin of West Texas, installing a total of 177 miles of oil and gas gathering lines. Three central production facility expansions were completed in early 2015 that added 30 MBbls/d of capacity. In addition, four new central gathering facilities (CGFs) were installed and two existing CGFs were expanded to add a total of 110 MMcf/d of compression capacity. Additional CGFs within the field are planned for 2016. In 2014, the Company entered into a joint-venture agreement with a third-party operator to construct the Mi Vida plant, a 200-MMcf/d cryogenic plant located in Loving County, Texas. The Mi Vida plant came online in May 2015 and is processing in excess of 200 MMcf/d.
In November 2014, WES acquired Nuevo Midstream, LLC (Nuevo). Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM). The DBM assets acquired by WES continue to be upgraded and enhanced to meet the producer gathering and processing needs in the region. The assets include a 300-MMcf/d cryogenic gas-processing plant. In December 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. There were no serious injuries and the majority of damage from the incident was to the liquid-handling facilities and the amine-treating units at the inlet of the complex. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and is expected to be returned to service by the end of 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and is expected to be able to accept limited deliveries of gas by the end of the first quarter of 2016, and it is expected to return to full service by the end of the second quarter of 2016, along with new liquid-handling and amine-treating facilities. There was no damage to Trains IV and V (each with a capacity of 200 MMcf/d), which were under construction at the time of the incident. Train IV is expected to come online during the first half of 2016 and Train V is expected to come online during the second half of 2016. WES has a property damage insurance policy designed to cover costs to repair or rebuild damaged assets (less a minimal deductible), and business interruption insurance designed to cover lost earnings after January 2, 2016. Insurance claims are in process under both of these policies.

Greater Natural Buttes  The Chipeta plant’s total processing capacity (cryogenic and refrigeration) is approximately 1 Bcf/d with cryogenic processing capacity of 550 MMcf/d. Chipeta’s third-party pipeline interconnect has added over 100 MMcf/d of natural-gas supply to the plant. In 2015, the Company continued to implement optimization projects to improve reliability and efficiency.

Eagleford  In the Eagleford shale, Anadarko continued the expansion of its infield gathering system with the completion of approximately 20 miles of gathering pipelines and laterals that connected 16 new central production facilities. The 200-MMcf/d operated Brasada natural-gas cryogenic processing plant continued steady operations at 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 2015. The high-pressure Haynesville gathering system and related water and condensate infrastructure were expanded in the Carthage area to handle the continued growth associated with the Haynesville natural-gas production. Additionally, Anadarko retained access to 420 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 and Bradford Counties in Pennsylvania. In 2015, the Company connected 2 Anadarko-operated wells and 25 nonoperated wells and constructed 42 miles of new pipeline. The Company commissioned three compressor stations in Lycoming County, which allowed an incremental 127 MMcf/d of low-pressure gathering.

The following provides information regarding the Company’s midstream assets by geographic regions:
Area
 
Asset Type
 
Miles of
Gathering
Pipelines
 
Total
Horsepower
 
2015
Average Net
Throughput
(MMcf/d)
Rocky Mountains
 
Gathering, processing, and treating
 
11,100

 
779,400

 
3,200

Southern and Appalachia
 
Gathering, processing, and treating
 
6,600

 
724,000

 
2,400

Total
 
 
 
17,700

 
1,503,400

 
5,600


MARKETING ACTIVITIES

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

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, condensate, 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.


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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.

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 integrated 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 22—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and for additional information on risk associated with international operations, see Risk Factors under Item 1A of this Form 10-K.

EMPLOYEES

The Company had approximately 5,800 employees at December 31, 2015.

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, local, and foreign 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, imposes various pre-construction, monitoring, and reporting requirements, which the Environmental Protection Agency has relied upon as authority for adopting climate change regulatory initiatives
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 and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States
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 obligations for establishing financial assurances for decommissioning activities, liabilities for pollution cleanup costs resulting from operations, and potential liabilities 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

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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
the National Environmental Policy Act, which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment

These U.S. 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 permitting, development or expansion 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; proposed well control rule for the Outer Continental Shelf; 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.
Many states where the Company operates also have, or are developing, similar environmental laws and regulations governing many of these same types of activities. In addition, many foreign countries where the Company is conducting business also have, or may be developing, regulatory initiatives or analogous controls that regulate Anadarko’s environmental-related activities. While the legal requirements imposed under state or foreign law may be similar in form to U.S. laws and regulations, 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 permitting, development or expansion of a project or substantially increase the cost of doing business. In addition, environmental laws and regulations, including new or amended legal requirements that may arise in the future to address potential environmental concerns such as air and water impacts, are expected to continue to have an increasing impact on the Company’s operations.
The Company has reviewed its potential responsibilities under both OPA and CWA as they relate to the Deepwater Horizon events. In December 2010, the U.S. Department of Justice on behalf of the United States, filed a civil lawsuit in the Louisiana District Court against several parties, including the Company, seeking an assessment of civil penalties under the CWA in an amount to be determined by the U.S. District Court in New Orleans, Louisiana (Louisiana District Court). After previously finding that Anadarko, as a nonoperating investor in the Macondo well, was not culpable with respect to the Deepwater Horizon events, the Louisiana District Court found Anadarko liable for civil penalties under the CWA as a working-interest owner in the Macondo well and entered a judgment of $159.5 million in December 2015. For additional information regarding the Company’s potential responsibilities under OPA, the CWA, or other legal requirements, see Note 15—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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The Company has incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. 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 more stringent requirements as 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 set forth procedures for a rapid and effective response to spill events that may occur as a result of Anadarko’s operations. The Plans are reviewed by the Company at least annually and updated as necessary. Drills are conducted by the Company 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 and any revisions to the Plans must be approved by the BSEE.
As part of the Company’s oil spill-response preparedness, and as set forth in the Plans, Anadarko maintains membership in CGA and has an employee representative on the executive committee of CGA. CGA was created to provide a means of effectively staging response equipment and to provide effective spill-response capability for its member companies operating in the Gulf of Mexico. CGA equipment includes, among other things, skimming vessels, barges, boom, and dispersants. CGA has executed a support contract with T&T Marine to coordinate bareboat charters and to provide for expanded response support. T&T Marine is responsible for inspecting, maintaining, storing, and staging 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 has service contracts in place with domestic environmental contractors as well as with other companies that provide for 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. 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 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, among other things, skimmers, OSRVs, fast response vessels, barges, storage bladders, work boats, ocean boom, and dispersant.

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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 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 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 is intended to satisfy the requirements of relevant local or national authorities, describes the actions the Company is expected to take in the event of an incident, includes drills conducted by the Company 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, among other things, 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.

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 tracts 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.


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EXECUTIVE OFFICERS OF THE REGISTRANT
Name
 
Age at
January 31,
2016
 
Position
R. A. Walker
 
58
 
Chairman, President and Chief Executive Officer
Robert P. Daniels
 
57
 
Executive Vice President, International and Deepwater Exploration
Robert G. Gwin
 
52
 
Executive Vice President, Finance and Chief Financial Officer
Darrell E. Hollek
 
58
 
Executive Vice President, U.S. Onshore Exploration and Production
Mitchell W. Ingram
 
53
 
Executive Vice President, Global LNG
James J. Kleckner
 
58
 
Executive Vice President, International and Deepwater Operations
Robert K. Reeves
 
58
 
Executive Vice President, Law and Chief Administrative Officer
Christopher O. Champion
 
46
 
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 a director of CenterPoint Energy, Inc. from April 2010 to April 2015, and has served 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.
Mr. Hollek was named Executive Vice President, U.S. Onshore Exploration and Production in April 2015. Prior to this position, he served as Senior Vice President, Deepwater Americas Operations since May 2013. Prior to this position, he served as Vice President, Operations since May 2007. Mr. Hollek 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, where he began his career, including management roles in the Gulf of Mexico; U.S. onshore; and Environmental, Health, Safety and Regulatory. Mr. Hollek has served as a director of WGH and WGEH since May 2015.

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Mr. Ingram was named Executive Vice President, Global LNG in November 2015. Prior to joining Anadarko, Mr. Ingram was with BG Group since 2006, where he served as a member of the Executive Committee in the role of Executive Vice President—Technical since March 2015. Previously, he held positions of increasing responsibility with the company’s LNG project in Queensland, Australia, where he served as Managing Director of QGC, a BG Group business, since April 2014, Deputy Managing Director since September 2013, and Project Director of the Queensland Curtis LNG project since May 2012. From 2006 to May 2012, Mr. Ingram was Asset General Manager of BG Group’s Karachaganak interest in Kazakhstan. He joined BG Group after 20 years with Occidental Oil & Gas where he held several U.K. and international leadership positions in project management, development, and operations.
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. Reeves was named Executive Vice President, Law and Chief Administrative Officer in September 2015 and previously served as Executive Vice President, General Counsel and Chief Administrative Officer since May 2013 and 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.
Mr. Champion was named Vice President, Chief Accounting Officer and Controller in June 2015. Prior to joining Anadarko, Mr. Champion was an Audit Partner with KPMG LLP since October 2003 and served as KPMG’s National Audit Leader for Oil and Natural Gas since 2008. He began his career at Arthur Andersen LLP in 1992 before joining KPMG LLP in 2002 as a senior audit manager.
Officers of Anadarko are elected each year at the first meeting of the Board following the annual meeting of stockholders, the next of which is expected to occur on May 10, 2016, 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 Form 10-K, 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
levels of oil, natural-gas, and natural-gas liquids (NGLs) reserves
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 oil, natural gas, 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, nationally, internationally, or in the jurisdictions in which the Company is, or in the future may be, 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
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 or refinance 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

Oil, natural-gas, and NGLs price volatility, including the recent decline in the price for these commodities, could adversely affect our financial condition and results of operations.

Prices for oil, natural gas, and NGLs can fluctuate widely. For example, New York Mercantile Exchange (NYMEX) West Texas Intermediate oil prices have been volatile and ranged from a high of $107.26 per barrel in June 2014 to a low of $26.21 per barrel in February 2016. Also, NYMEX Henry Hub natural-gas prices have been volatile and ranged from a high of $6.15 per million British thermal units (MMBtu) in February 2014 to a low of $1.76 per MMBtu in December 2015. The duration and magnitude of the decline in oil and natural-gas prices cannot be predicted. 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:
 
the domestic and worldwide supply of, and demand for, oil, natural gas, and NGLs
volatility and trading patterns in the commodity-futures markets
the cost of exploring for, developing, producing, transporting, and marketing oil, natural gas, and NGLs
the level of global oil and natural-gas inventories
weather conditions
the level of U.S. exports of oil, condensate, liquefied natural gas, or NGLs
the ability of the members of the Organization of the Petroleum Exporting Countries (OPEC) and other producing nations to agree to and maintain production levels
the 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 acts of terrorism in the United States or elsewhere
the effect of worldwide energy conservation and environmental protection efforts

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the price and availability of alternative and competing fuels
the level of foreign imports of oil, natural gas, and NGLs
domestic and foreign governmental laws, regulations, and taxes
the 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 further declines in these commodity prices may have the following effects on our business:
 
adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations
reducing the amount of oil, natural gas, and NGLs that we can produce economically
causing us to delay or postpone some of our capital projects
reducing our revenues, operating income, or cash flows
reducing the amounts of our estimated proved oil, natural-gas, and NGLs reserves
reducing the carrying value of our oil, natural-gas, and midstream properties due to recognizing additional impairments of proved properties, unproved properties, exploration assets, and midstream facilities
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


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

As of December 31, 2015, our long-term debt was rated “BBB” with a stable outlook by both Standard and Poor’s (S&P) and Fitch Ratings (Fitch), and our commercial paper program was rated “A-2” by S&P and “F2” by Fitch. Our long-term debt was rated “Baa2” with a stable outlook and our commercial paper program was rated “P2” by Moody’s Investors Service (Moody’s) until December 16, 2015, when Moody’s announced that it had placed both ratings under review for downgrade along with the ratings of 28 other U.S. exploration and production companies and their related subsidiaries. In February 2016, S&P affirmed our “BBB” rating and changed the outlook from stable to negative. As of the time of filing this Form 10-K, neither Fitch nor Moody’s had announced any change to our credit ratings; however, we cannot be assured that our credit ratings will not be downgraded. Any downgrade in our credit ratings could negatively impact our cost of capital, and a downgrade to a level that is below investment grade could also adversely affect our ability to effectively execute aspects of our strategy or to raise debt in the public debt markets.
In the event of a downgrade in our credit rating to a level that is below investment grade, we may be required to post collateral in the form of letters of credit or cash as financial assurance of our performance under certain contractual arrangements such as pipeline transportation contracts and oil and gas sales contracts. At December 31, 2015, there were no letters of credit or cash provided as assurance of our performance under these type of contractual arrangements with respect to credit-risk-related contingent features. If our credit ratings had been downgraded to a level below investment grade as of December 31, 2015, the collateral required to be posted under these arrangements would have been $460 million. Additionally, certain of these arrangements contain financial assurances language that may, under certain circumstances, permit our counterparties to request additional collateral.
Furthermore, in the event of a downgrade to a level that is below investment grade, the credit thresholds with our derivative counterparties may be reduced or, in certain cases, eliminated, which may require the posting of additional collateral in the form of letters of credit or cash. The aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed on December 31, 2015, was $1.3 billion, net of collateral. As of December 31, 2015, $58 million was posted as cash collateral with our derivative counterparties. For additional information, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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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
drilling activities on certain lands lying within wilderness, wetlands, and other protected areas
types, quantities, and concentrations of emissions, discharges, and authorized releases
generation, management, and disposition of waste materials
offshore oil and natural-gas operations and decommissioning of abandoned facilities
reclamation and abandonment of wells and facility sites
remediation of contaminated sites
protection of endangered species

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 permitting, development, or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Moreover, changes in, or reinterpretations of, environmental laws and regulations governing areas where we operate may negatively impact our operations. Examples of recent proposed and final regulations include the following:
Proposed Outer Continental Shelf Well Control Rule. In April 2015, the Bureau of Safety and Environmental Enforcement (BSEE) issued a notice of proposed rulemaking entitled Oil and Sulfur Operations on the Outer Continental Shelf - Blowout Preventer Systems and Well Control that focuses on well blowout preventer systems and well control with respect to operations on the Outer Continental Shelf. The proposed rule requires, among other things, incorporation of the latest industry standards establishing minimum baseline standards for the design, manufacture, repair, and maintenance of blowout preventers as well as more controls over the maintenance and repair of blowout preventers. This rulemaking is expected to be finalized in 2016.
Ground-Level Ozone Standards. In October 2015, the U.S. Environmental Protection Agency (EPA) issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The final rule became effective in December 2015. Certain areas of the country in compliance with the ground-level ozone NAAQS standard may be reclassified as non-attainment and such reclassification may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Moreover, states are expected to implement more stringent regulations, which could apply to our operations. Compliance with this final rule could, among other things, require installation or new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.
Reduction of Methane Emissions by the Oil and Gas Industry. In August 2015, the EPA proposed rules that will establish emission standards for methane from certain new and modified oil and natural-gas production and natural-gas processing and transmission facilities as part of the Obama Administration’s efforts to reduce methane emissions from the oil and natural-gas sector by up to 45 percent from 2012 levels by 2025. The EPA’s proposed rule package includes standards to address emissions of methane from equipment and processes across the source category, including hydraulically-fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural-gas processing plants and pneumatic pumps. The EPA is expected to finalize these rules in 2016.

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Reduction of Greenhouse Gas Emissions. The U.S. Congress and the EPA, in addition to some state and regional efforts, have in recent years considered legislation or regulations to reduce emissions of greenhouse gases (GHGs). These efforts have included consideration of cap-and-trade programs, carbon taxes, and GHG reporting and tracking programs. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “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. 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. On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets.

These and other regulatory changes could significantly increase our capital expenditures and operating costs or could result in delays to or limitations on our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows. For a description of certain environmental proceedings in which we are involved, see Legal Proceedings under Item 3 and Note 15—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Changes in laws or regulations regarding hydraulic fracturing or other oil and natural-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 oil and natural gas 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 typically 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 issued Clean Air Act final regulations in 2012 and proposed additional Clean Air Act regulations in August 2015 governing performance standards for the oil and natural-gas industry; proposed in April 2015 effluent limitations guidelines that waste water from shale natural-gas extraction operations must meet before discharging to a treatment plant; and issued in 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, the Bureau of Land Management (BLM) published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands but, in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and is being separately appealed by certain environmental groups. 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.

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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 other regulatory requirements on hydraulic-fracturing operations, including subsurface water disposal. States could elect to prohibit hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. For example, several cities in Colorado passed temporary or permanent moratoria on hydraulic fracturing within their respective city limits in 2012 and 2013. Since that time, in response to lawsuits brought by an industry trade group, local district courts struck down the ordinances for certain of those Colorado cities in 2014, primarily on the basis that state law preempts local bans on hydraulic fracturing. A suit brought by the trade group against at least one other Colorado city, Broomfield, remains pending. The cities of Fort Collins and Longmont, among those cities whose ordinances were struck down in 2014, were notified in September 2015 by the Colorado Supreme Court that the high court had agreed to hear their appeals. Notwithstanding attempts at the local level to prohibit hydraulic fracturing, the opportunity exists for cities to adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions while regulating the time, place, and manner of those activities.
In addition, certain interest groups in Colorado opposed to oil and natural-gas development generally, and hydraulic fracturing in particular, have from time to time advanced various ballot initiatives aimed at significantly limiting or preventing oil and natural-gas development. In response to one such set of initiatives, 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 natural-gas resources. In February 2015, the Task Force made several non-binding recommendations to the Colorado Governor, and recently, the Colorado Oil and Gas Conservation Commission (COGCC) undertook a rulemaking process to implement those recommendations. It is possible that the COGCC could undertake additional rulemaking procedures or the Colorado state legislature could introduce and seek to adopt additional legislation relating to oil and natural-gas operations that could limit or prevent oil and natural-gas development. In addition, several ballot initiatives have been proposed for inclusion on the Colorado state ballot in November 2016. Although it is early in the political process, if approved, these initiatives, or others that may be proposed, could give local governments in Colorado greater authority to limit hydraulic fracturing, require greater distances between certain well sites and occupied structures, or otherwise limit the production and development of oil and natural gas.
In the event that ballot initiatives, local or state restrictions, or prohibitions are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we conduct operations, including the Wattenberg field in Colorado, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the permitting or pursuit of exploration, development, or production activities. In addition, we could 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 compliance costs and delays, curtailments, limitations, 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 June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not lead to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided its comments on the draft study, indicating its concern that the EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, when issued, as well as other 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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We may be subject to claims and liabilities relating to the Deepwater Horizon events that result in losses, 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, we 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, we are 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. We are not indemnified against penalties and fines, punitive damages, shareholder derivative or securities laws claims, or certain other claims.
In July 2015, BP announced a settlement agreement in principle with the Department of Justice and certain states and local government entities regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event (BP Settlement) and, in October 2015, lodged a proposed consent decree with the Louisiana District Court. Essentially all claims and liabilities relating to the Deepwater Horizon events that are covered by BP’s indemnification obligations under our Settlement Agreement will be resolved as part of the BP Settlement, provided that the consent decree is ultimately approved by the Louisiana District Court. A hearing related to the consent decree is currently scheduled for March 2016. In the event the consent decree is not approved by the Louisiana District Court, 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. 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. For additional information, see Note 15—ContingenciesDeepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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

Our total debt was $15.8 billion at December 31, 2015. 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% (excluding the effect of non-cash write-downs), 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.

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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 Form 10-K represents estimates prepared by our internal engineers. The procedures and methods for estimating the reserves by our internal engineers were reviewed by independent petroleum consultants; however, no reserves audit was conducted by these consultants. Estimation of reserves is not an exact science. Estimates of economically recoverable oil and natural-gas reserves and of future net cash flows depend on a number of variable factors and assumptions, any of which may cause actual results to vary considerably from these estimates. These factors and assumptions may include, but are not limited to, the following:
 
historical production from an area compared with production from similar producing areas
assumed effects of regulation by governmental agencies and court rulings
assumptions concerning future oil and natural-gas prices, future operating costs, and capital expenditures
estimates of future severance and excise taxes, workover costs, and remedial costs

Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The discounted cash flows included in this Form 10-K 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. Therefore, reserves quantities will change when actual prices increase or decrease.

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.

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, and 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 such as the adoption of government-payment-transparency regulations. For example, from time to time, deficit reduction or tax reform legislation has been proposed that could adversely affect our business, financial condition, results of operations, or cash flows. Proposals have included 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, (iii) eliminate accelerated depreciation for tangible property, and (iv) treat publicly traded partnerships for fossil fuels as C corporations.

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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 and impede the execution of long-term sales agreements or prices thereunder which are the basis for future LNG production; 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 $5.4 billion of goodwill on our Consolidated Balance Sheet at December 31, 2015. 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 reduce the fair value of a reporting unit such as our inability to replace the value of our 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 lead to an impairment of goodwill. An impairment of goodwill could have a substantial negative effect on our profitability.

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, Ghana, Mozambique, Colombia, Côte d’Ivoire, New Zealand, Kenya, 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 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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Additional domestic and international deepwater drilling laws, regulations, and other restrictions; delays in the processing and approval of drilling permits and exploration, development, oil spill-response, and decommissioning 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 2010, the Bureau of Ocean Energy Management (BOEM) and the BSEE, agencies of the U.S. Department of the Interior, imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these more stringent rules and regulations, together with any uncertainties or inconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could adversely affect or delay new drilling and ongoing development efforts. In addition, new regulatory initiatives may be adopted or enforced by the BOEM and/or the BSEE in the future that could result in additional delays, restrictions, or obligations with respect to oil and natural-gas exploration and production operations conducted offshore. For example, in September 2015, the BOEM issued draft guidance that would bolster supplemental bonding procedures for the decommissioning of offshore wells, platforms, pipelines, and other facilities. The BOEM is expected to issue the draft guidance in the form of a final Notice to Lessees and Operators by no later than early summer 2016. These existing rules, or any new rules, regulations, or legal initiatives 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 or result in the suspension or cancellation of leases. Also, if material spill events similar to the Deepwater Horizon incident 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, regulations, or legal initiatives on our drilling operations or on the cost or availability of insurance to cover the risks associated with such operations. The overall costs to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete.
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 our oil spill-response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to potential material events in the future.
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.


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

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

For example, Ghana and Côte d’Ivoire are engaged in a dispute regarding the international maritime boundary 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 close to or 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 our financial condition, results of operations, or cash flows.


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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 our 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 Commodity 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 position limits rule, remain to be finalized or effectuated, and therefore, the impact of those rules and regulations on us is uncertain at this time. Moreover, the phase-in threshold for swap dealer de minimis purposes is set to expire on December 31, 2017, (and thereby revert from $8 billion to $3 billion) unless the CFTC acts to maintain or change the current $8 billion threshold before that time. The financial reform legislation may require our compliance with a lower de minimis threshold, as well as with margin, position limits, clearing, and trade-execution requirements if certain hedging exemptions are unavailable. Although we expect to qualify for exceptions to such requirements for swaps entered to hedge our commercial risks, the application of such requirements, including to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. Moreover, the framework of what qualifies as a bona fide hedge for position-limits purposes is yet uncertain.
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, and (iii) reduce the availability of derivatives to protect against risks we encounter. 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 we transact with counterparties in foreign jurisdictions, those transactions may become subject to such regulations. At this time, the impact of such regulations is not clear.


41


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 facilities 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 facilities. Moreover, to the extent that purchasers of our 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 us 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 natural gas, including blowouts; cratering and fire; environmental hazards such as natural-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.

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.


42


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 integrated 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.

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. 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.


43


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 or timing 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.

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 those of third parties 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.


44


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. In response to the current commodity-price environment, the Company decreased the quarterly dividend from $0.27 per share to $0.05 per share in February 2016. The amount of cash dividends, if any, to be paid in the future is determined by our Board of Directors based on our financial condition, results of operations, cash flows, levels of capital and exploration expenditures, future business prospects, expected liquidity needs, and other 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 could be intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

Item 1B.  Unresolved Staff Comments

None.

Item 3.  Legal Proceedings

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 personal injury and death claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas exploration, development, 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, tribal, 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.
WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the EPA with respect to 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 15—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.

45


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 29, 2016, there were approximately 10,870 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 2015 and 2014:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2015
 
 
 
 
 
 
 
Market Price
 
 
 
 
 
 
 
High
$
90.10

 
$
95.94

 
$
78.70

 
$
73.87

Low
$
73.82

 
$
77.75

 
$
58.10

 
$
44.50

Dividends
$
0.27

 
$
0.27

 
$
0.27

 
$
0.27

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


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—Financing Activities—Common Stock Dividends and Distributions to Noncontrolling Interest Owners under Item 7 of this Form 10-K.

46


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, 2015:
Plan Category
 
(a)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants, and rights
 
(b)
Weighted-average
exercise price of
outstanding
options, warrants,
and rights
 
(c)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column(a))
Equity compensation plans approved by security holders
 
7,046,098

 
$
71.86

 
16,378,707

Equity compensation plans not approved by security holders
 

 

 

Total
 
7,046,098

 
$
71.86

 
16,378,707


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 2015:
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 1-31, 2015
 
186,340

 
$
70.32

 

 
 
November 1-30, 2015
 
63,867

 
$
69.09

 

 
 
December 1-31, 2015
 
1,903

 
$
56.61

 

 
 
Total
 
252,110

 
$
69.90

 

 
$

 _______________________________________________________________________________
(1) 
During the fourth quarter of 2015, 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 19—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

47


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© 2016 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, 2010, and its relative performance is tracked through December 31, 2015. 
Fiscal Year Ended December 31
2010
 
2011
 
2012
 
2013
 
2014
 
2015
Anadarko Petroleum Corporation
$
100.00

 
$
100.70

 
$
98.53

 
$
105.81

 
$
111.25

 
$
66.53

S&P 500
100.00

 
102.11

 
118.45

 
156.82

 
178.29

 
180.75

Peer Group
100.00

 
105.57

 
107.65

 
135.30

 
124.85

 
95.82


48


Item 6.  Selected Financial Data
 
Summary Financial Information (1)
millions except per-share amounts
2015
 
2014
 
2013
 
2012
 
2011
Sales Revenues
$
9,486

 
$
16,375

 
$
14,867

 
$
13,307

 
$
13,882

Gains (Losses) on Divestitures and Other, net
(788
)
 
2,095

 
(286
)
 
104

 
85

Total Revenues and Other
8,698

 
18,470

 
14,581

 
13,411

 
13,967

Other Operating (Income) Expense
 
 
 
 
 
 
 
 
 
Algeria Exceptional Profits Tax Settlement

 

 
33

 
(1,797
)
 

Deepwater Horizon Settlement and Related Costs
74

 
97

 
15

 
18

 
3,930

Operating Income (Loss)
(8,809
)
 
5,403

 
3,333

 
3,727

 
(1,870
)
Tronox-related Contingent Loss
5

 
4,360

 
850

 
(250
)
 
250

Income (Loss)
(6,812
)
 
(1,563
)
 
941

 
2,445

 
(2,568
)
Net Income (Loss) Attributable to Common Stockholders
(6,692
)
 
(1,750
)
 
801

 
2,391

 
(2,649
)
Per Common Share (amounts attributable to common stockholders)
 
 
 
 
 
 
 
 
 
Net Income (Loss)—Basic
$
(13.18
)
 
$
(3.47
)
 
$
1.58

 
$
4.76

 
$
(5.32
)
Net Income (Loss)—Diluted
$
(13.18
)
 
$
(3.47
)
 
$
1.58

 
$
4.74

 
$
(5.32
)
Dividends
$
1.08

 
$
0.99

 
$
0.54

 
$
0.36

 
$
0.36

Average Number of Common Shares Outstanding—Basic
508

 
506

 
502

 
500

 
498

Average Number of Common Shares Outstanding—Diluted
508

 
506

 
505

 
502

 
498

Cash Provided by (Used in) Operating Activities
(1,877
)
 
8,466

 
8,888

 
8,339

 
2,505

Capital Expenditures
$
5,888

 
$
9,256

 
$
8,523

 
$
7,311

 
$
6,553

Current Portion of Long-term Debt
$
33

 
$

 
$
500

 
$

 
$
170

Long-term Debt (2)
15,718

 
15,092

 
13,065

 
13,269

 
15,060

Total Debt
$
15,751

 
$
15,092

 
$
13,565

 
$
13,269

 
$
15,230

Total Stockholders’ Equity
12,819

 
19,725

 
21,857

 
20,629

 
18,105

Total Assets (3)
$
46,414

 
$
60,967

 
$
55,421

 
$
52,261

 
$
51,641

Annual Sales Volumes
 
 
 
 
 
 
 
 
 
Oil and Condensate (MMBbls)
116

 
106

 
91

 
86

 
79

Natural Gas (Bcf)
852

 
945

 
968

 
913

 
852

Natural Gas Liquids (MMBbls)
47

 
44

 
33

 
30

 
27

Total (MMBOE) (4)
305

 
308

 
285

 
268

 
248

Average Daily Sales Volumes
 
 
 
 
 
 
 
 
 
Oil and Condensate (MBbls/d)
317

 
292

 
248

 
233

 
217

Natural Gas (MMcf/d)
2,334

 
2,589

 
2,652

 
2,495

 
2,334

Natural Gas Liquids (MBbls/d)
130

 
119

 
91

 
83

 
74

Total (MBOE/d)
836

 
843

 
781

 
732

 
680

Proved Reserves
 
 
 
 
 
 
 
 
 
Oil and Condensate Reserves (MMBbls)
713

 
929

 
851

 
767

 
771

Natural-gas Reserves (Tcf)
6.0

 
8.7

 
9.2

 
8.3

 
8.4

Natural-gas Liquids Reserves (MMBbls)
340

 
479

 
407

 
405

 
374

Total Proved Reserves (MMBOE)
2,057

 
2,858

 
2,792

 
2,560

 
2,539

Number of Employees
5,800

 
6,100

 
5,700

 
5,200

 
4,800

(1) 
Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
(2) 
Includes Western Gas Partners, LP debt of $2.7 billion at December 31, 2015, $2.4 billion at December 31, 2014, $1.4 billion at December 31, 2013, $1.2 billion at December 31, 2012, and $494 million at December 31, 2011.
(3) 
As a result of adopting Accounting Standards Update 2015-17, Balance Sheet Classification of Deferred Taxes, the Company reclassified other current assets of $722 million in 2014, $360 million in 2013, $328 million in 2012, and $138 million in 2011, to deferred income taxes. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
(4) 
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