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. | ||
Regulatory and Environmental Matters | ||
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.
2
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.
3
OIL AND GAS PROPERTIES AND ACTIVITIES
The map below illustrates the locations of Anadarko’s significant oil and natural-gas exploration and production operations:
4
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.
5
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.
6
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.
7
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.
8
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.
9
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.
10
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.
11
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.
21
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.
22
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 |
23
• | 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.
24
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.
25
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.
26
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.
27
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.
28
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 |
29
• | 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 |
30
• | 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 |
31
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.
32
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. |
33
• | 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.
34
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.
35
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—Contingencies—Deepwater 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.
36
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.
37
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.
38
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.
39
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.
40
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 | MMcf/d—Million cubic feet per day | Tcf—Trillion cubic feet | ||
MMBbls—Million barrels | MBbls/d—Thousand barrels per day | |||
MMBOE—Million barrels of oil equivalent | MBOE/d—Thousand barrels of oil equivalent per day | |||
49
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.
MISSION AND STRATEGY
Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:
• | explore in high-potential, proven basins |
• | identify and commercialize resources |
• | employ a global business development approach |
• | ensure financial discipline and flexibility |
Exploring in high-potential, proven basins worldwide provides the Company with growth opportunities. Anadarko’s exploration success has created value by increasing future resource potential while providing the flexibility to mitigate risk by monetizing discoveries.
Developing a portfolio of primarily unconventional resources provides the Company a stable base of capital-efficient and predictable development opportunities that, in turn, position the Company for consistent growth at competitive rates.
Anadarko’s global business development approach transfers core skills across the globe to assist in the discovery and development of world-class resources that are accretive to the Company’s performance. These resources help form an optimized global portfolio where both surface and subsurface risks are actively managed.
A strong balance sheet is essential for the development of the Company’s assets, and Anadarko is committed to disciplined investment in its businesses to efficiently manage commodity-price cycles. Maintaining financial discipline enables the Company to capitalize on the opportunities afforded by its global portfolio while allowing the Company to pursue new strategic growth opportunities.
50
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’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly dependent on the global commodity-price markets, which affect the value the Company receives from its sales of oil, natural-gas, and natural-gas liquids (NGLs) production. The Company’s strategy in 2015 was to preserve and build value by focusing a greater percentage of its capital investment on longer-dated projects while driving cost savings and efficiencies through every aspect of its business. During 2015, the Company closed $2.0 billion of monetizations and was successful in lowering its capital expenditures by 36% and its operating expenses by 13% compared to 2014 while maintaining relatively flat production year over year.
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 the Company’s 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.
Liquidity As of December 31, 2015, Anadarko had $939 million of cash on hand plus $4.75 billion of borrowing capacity under its revolving credit facilities ($5.0 billion capacity, less $250 million of outstanding commercial paper notes). Substantially all of Anadarko’s cash balances at December 31, 2015, were domiciled in the United States and were available to support its worldwide operations. In addition, future excess cash flows generated from the Company’s international assets are available to support both its U.S. operations and corporate needs without incurring incremental U.S. income tax. In December 2015, Anadarko extended the maturity of its $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility) to January 2021, and in January 2016, Anadarko replaced its $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility) with a new $2.0 billion 364-day senior unsecured revolving credit facility that will mature in January 2017. The extension and renewal included no changes to covenants or pricing, and the original bank-group fully participated.
Anadarko’s $1.750 billion 5.950% Senior Notes, scheduled to mature in September 2016, were classified as long-term debt on the Company’s Consolidated Balance Sheet at December 31, 2015, as Anadarko intends to refinance these obligations prior to or at maturity with new long-term debt issuances or by using the Five-Year Facility.
As of December 31, 2015, Anadarko’s long-term debt was rated “BBB” with a stable outlook by both Standard and Poor’s (S&P) and Fitch Ratings (Fitch), and its commercial paper program was rated “A-2” by S&P and “F2” by Fitch. Anadarko’s long-term debt was rated “Baa2” with a stable outlook and its 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 Anadarko’s “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 Anadarko’s credit ratings; however, the Company cannot be assured that its credit ratings will not be downgraded. Any downgrade in Anadarko’s credit ratings could negatively impact its cost of capital, and a downgrade to a level that is below investment grade could also adversely affect the Company’s ability to effectively execute aspects of its strategy or to raise debt in the public debt markets.
51
In the event of a downgrade in Anadarko’s credit rating to a level that is below investment grade, the Company may be required to post collateral in the form of letters of credit or cash as financial assurance of its 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 the Company’s performance under these types of contractual arrangements with respect to credit-risk-related contingent features. If Anadarko’s 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 the counterparties to request additional collateral. For additional information, see Risk Factors in Item 1A of this Form 10-K.
Furthermore, in the event of a downgrade in Anadarko’s credit rating to a level that is below investment grade, the credit thresholds with Anadarko’s derivative counterparties may be reduced or, in certain cases, eliminated, which may require the Company to post 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 Anadarko’s 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.
Anadarko believes that its cash on hand, anticipated operating cash flows, and proceeds from expected asset monetizations will be sufficient to fund the Company’s projected 2016 operational and capital programs. In response to the current commodity-price environment, the Board decreased the quarterly dividend from $0.27 per share to $0.05 per share in February 2016. On an annualized basis, the dividend decrease will have the effect of providing approximately $450 million of additional cash available to enhance the Company’s operations and financial flexibility. Anadarko also expects to receive an $881 million tax refund in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback. Further, Anadarko enters into strategic derivative positions to reduce commodity-price risk and increase the predictability of cash flows. At December 31, 2015, derivative positions covered approximately 26% of Anadarko’s anticipated oil sales volumes, 3% of its anticipated NGLs sales volumes, and 2% of its anticipated natural-gas sales volumes for 2016. These instruments had a fair value of $273 million as of December 31, 2015. See Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. Anadarko believes that the actions taken to enhance the Company’s liquidity position coupled with its asset portfolio and operating and financial performance provide the necessary financial flexibility to fund the Company’s current and long-term operations.
Potential for Future Impairments During 2015, the Company recognized significant impairments of proved oil and gas and midstream properties and impairments of unproved oil and gas properties, primarily as a result of lower forecasted commodity prices and changes to the Company’s drilling plans. At December 31, 2015, the Company’s estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $2.2 billion indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that, if this depletion group becomes impaired in a future period, the Company could recognize non-cash impairments in that period in excess of $800 million. It is also reasonably possible that prolonged low or further declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in other additional impairments.
Anadarko had approximately $5.4 billion of goodwill at December 31, 2015, allocated to the following reporting units: $4.9 billion to oil and gas exploration and production, $383 million to WES gathering and processing, $5 million to WES transportation, and $62 million to other gathering and processing. Goodwill is tested annually in October, and at interim periods when necessary. Although commodity prices declined during the year, as of December 31, 2015, the estimated fair value of the oil and gas reporting unit exceeded the carrying value by more than 15%, without consideration for any control premium, and the other reporting units were not at risk of impairment. However, it is reasonably possible that prolonged low or further declines in commodity prices, decreases in proved reserves, changes in exploration or development plans, significant property impairments, increases in operating or drilling costs, significant changes in regulations, or other negative changes to the economic environment in which Anadarko operates could result in a further reduction in the fair value of the reporting units and increase the potential for a future impairment of goodwill.
52
Proved Reserves 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 (MMBtu) for gas, and $19.47 per Bbl for NGLs. 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 Bbl in February 2016. Also, NYMEX Henry Hub natural-gas prices have been volatile and ranged from a high of $6.15 per MMBtu in February 2014 to a low of $1.76 per MMBtu in December 2015. 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.
OVERVIEW
Significant 2015 operating and financial activities include the following:
Total Company
• | Anadarko’s sales volumes averaged 836 thousand barrels of oil equivalent per day (MBOE/d), which was relatively flat compared to 2014 and includes a 37 MBOE/d decrease related to divestitures. |
• | The Company’s overall sales-volume product mix increased to 53% liquids in 2015 compared to 49% in 2014. |
• | Anadarko’s higher-margin liquids sales volumes were 447 thousand barrels per day (MBbls/d), representing a 9% increase over 2014. This increase included a 14 MBbls/d decrease in sales volumes related to divestitures, including certain enhanced oil recovery (EOR) assets in the Rocky Mountains Region (Rockies) in 2015 and the Company’s Chinese subsidiary in 2014. |
• | The Company closed several asset monetizations, totaling $1.4 billion, including the divestiture of certain coalbed methane properties and related midstream assets in the Rockies, certain EOR assets in the Rockies, and certain oil and gas properties and related midstream assets in East Texas. |
• | Anadarko paid $5.2 billion related to a settlement agreement resolving all claims asserted in the Tronox Adversary Proceeding. See Note 15—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
• | 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 Clean Water Act as a working-interest owner in the Macondo well and entered a judgment of $159.5 million in December 2015. See Note 15—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
U.S. Onshore
• | The Rockies sales volumes averaged 367 MBOE/d, representing a 2%, or 6 MBOE/d, increase over 2014, primarily from a 32%, or 54 MBOE/d, sales volume increase in the Wattenberg field, partially offset by lower sales volumes due to the April 2015 sale of certain EOR assets and the September 2015 sale of certain coalbed methane properties. |
• | The Southern and Appalachia Region sales volumes averaged 284 MBOE/d, representing a 5% decrease from 2014, primarily due to lower natural-gas sales volumes in the Marcellus shale due to voluntary curtailments and third-party infrastructure downtime, and the sale of certain U.S. onshore oil and gas properties and related midstream assets in East Texas, partially offset by higher sales volumes in the Eagleford shale. |
53
Gulf of Mexico
• | Gulf of Mexico sales volumes averaged 85 MBOE/d, representing a 2% increase over 2014, primarily due to the commencement of oil production from the Lucius development in January 2015, partially offset by a natural-gas production decline at Independence Hub (IHUB). |
• | The Company participated in the successful drilling of the nonoperated Yeti exploration well (37.5% working interest) in Walker Ridge Block 160, with the well successfully sidetracked to test the down-dip limits of the field. |
• | Anadarko’s Heidelberg development project was completed and achieved first oil in January 2016. |
International
• | International sales volumes averaged 91 MBOE/d, which was relatively flat compared to 2014. |
• | The Kronos-1 deepwater prospect offshore Colombia encountered 130 to 230 net feet of natural-gas pay in the upper objective and encountered non-commercial hydrocarbons in a deeper objective. |
• | The Tweneboa/Enyenra/Ntomme (TEN) project in Ghana was more than 80% complete at year end 2015, with first oil expected in the third quarter of 2016. |
• | Anadarko wrote off suspended exploratory costs in Brazil where the Company does not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment and other considerations. |
Financial
• | Anadarko’s net loss attributable to common stockholders for 2015 totaled $6.7 billion, including impairments of $5.1 billion primarily related to certain U.S. onshore and Gulf of Mexico properties, impairments of exploration assets of $1.9 billion primarily associated with impairments of unproved properties and the write-off of suspended exploratory well costs in Brazil, and losses on divestitures of $1.0 billion. |
• | The Company’s net cash used in operating activities was $1.9 billion in 2015, which included the $5.2 billion Tronox settlement payment. The Company ended 2015 with $939 million of cash on hand. |
• | The Company initiated a commercial paper program, which allows the issuance of a maximum of $3.0 billion of unsecured commercial paper notes. |
• | In December 2015, Anadarko extended the maturity of its Five-Year Facility to January 2021, and in January 2016, Anadarko replaced its 364-Day Facility with a new $2.0 billion 364-day senior unsecured revolving credit facility that will mature in January 2017. |
• | WES, a publicly traded consolidated subsidiary, completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025. |
• | Anadarko issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per unit and raised net proceeds of $445 million. |
• | Anadarko completed a public secondary offering of 2.3 million common units in Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary that owns partnership interests in WES, and raised net proceeds of $130 million. |
54
FINANCIAL RESULTS
millions except per-share amounts | 2015 | 2014 | 2013 | ||||||||
Oil and condensate, natural-gas, and NGLs sales | $ | 8,260 | $ | 15,169 | $ | 13,828 | |||||
Gathering, processing, and marketing sales | 1,226 | 1,206 | 1,039 | ||||||||
Gains (losses) on divestitures and other, net | (788 | ) | 2,095 | (286 | ) | ||||||
Revenues and other | 8,698 | 18,470 | 14,581 | ||||||||
Costs and expenses | 17,507 | 13,067 | 11,248 | ||||||||
Other (income) expense | 880 | 5,349 | 1,227 | ||||||||
Income tax expense (benefit) | (2,877 | ) | 1,617 | 1,165 | |||||||
Net income (loss) attributable to common stockholders | $ | (6,692 | ) | $ | (1,750 | ) | $ | 801 | |||
Net income (loss) per common share attributable to common stockholders—diluted | $ | (13.18 | ) | $ | (3.47 | ) | $ | 1.58 | |||
Average number of common shares outstanding—diluted | 508 | 506 | 505 | ||||||||
The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the year ended December 31, 2015,” refer to the comparison of the year ended December 31, 2015, to the year ended December 31, 2014. Similarly, any increases or decreases “for the year ended December 31, 2014,” refer to the comparison of the year ended December 31, 2014, to the year ended December 31, 2013. The primary factors that affect the Company’s results of operations include commodity prices for oil, natural gas, and NGLs; sales volumes; the cost of finding such reserves; and operating costs.
Revenues and Sales Volumes
millions | Oil and Condensate | Natural Gas | NGLs | Total | |||||||||||
2014 sales revenues | $ | 9,748 | $ | 3,849 | $ | 1,572 | $ | 15,169 | |||||||
Changes associated with prices | (5,189 | ) | (1,462 | ) | (871 | ) | (7,522 | ) | |||||||
Changes associated with sales volumes | 861 | (380 | ) | 132 | 613 | ||||||||||
2015 sales revenues | $ | 5,420 | $ | 2,007 | $ | 833 | $ | 8,260 | |||||||
Increase/(decrease) vs. 2014 | (44 | )% | (48 | )% | (47 | )% | (46 | )% | |||||||
2013 sales revenues | $ | 9,178 | $ | 3,388 | $ | 1,262 | $ | 13,828 | |||||||
Changes associated with prices | (1,046 | ) | 540 | (86 | ) | (592 | ) | ||||||||
Changes associated with sales volumes | 1,616 | (79 | ) | 396 | 1,933 | ||||||||||
2014 sales revenues | $ | 9,748 | $ | 3,849 | $ | 1,572 | $ | 15,169 | |||||||
Increase/(decrease) vs. 2013 | 6 | % | 14 | % | 25 | % | 10 | % | |||||||
Changes associated with sales volumes for the years ended December 31, 2015 and 2014, include decreases associated with asset divestitures.
55
The following provides Anadarko’s sales volumes for the years ended December 31:
2015 | Inc/(Dec) vs. 2014 | 2014 | Inc/(Dec) vs. 2013 | 2013 | ||||||||||
Barrels of Oil Equivalent | ||||||||||||||
(MMBOE except percentages) | ||||||||||||||
United States | 272 | (1 | )% | 275 | 9 | % | 252 | |||||||
International | 33 | (1 | ) | 33 | 2 | 33 | ||||||||
Total barrels of oil equivalent | 305 | (1 | ) | 308 | 8 | 285 | ||||||||
Barrels of Oil Equivalent per Day | ||||||||||||||
(MBOE/d except percentages) | ||||||||||||||
United States | 745 | (1 | )% | 751 | 9 | % | 691 | |||||||
International | 91 | (1 | ) | 92 | 2 | 90 | ||||||||
Total barrels of oil equivalent per day | 836 | (1 | ) | 843 | 8 | 781 | ||||||||
MMBOE—million barrels of oil equivalent
Sales volumes represent actual production volumes adjusted for changes in commodity inventories and natural-gas production volumes provided to satisfy a commitment established in conjunction with the Jubilee development plan in Ghana. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Other (Income) Expense—(Gains) Losses on Derivatives, net. Production of natural gas, oil, and NGLs is usually not affected by seasonal swings in demand.
56
Oil and Condensate Sales Volumes, Average Prices, and Revenues
2015 | Inc/(Dec) vs. 2014 | 2014 | Inc/(Dec) vs. 2013 | 2013 | |||||||||||||
United States | |||||||||||||||||
Sales volumes—MMBbls | 85 | 14 | % | 74 | 28 | % | 58 | ||||||||||
MBbls/d | 232 | 14 | 203 | 28 | 158 | ||||||||||||
Price per barrel | $ | 45.00 | (49 | ) | $ | 87.99 | (9 | ) | $ | 97.02 | |||||||
International | |||||||||||||||||
Sales volumes—MMBbls | 31 | (4 | )% | 32 | (1 | )% | 33 | ||||||||||
MBbls/d | 85 | (4 | ) | 89 | (1 | ) | 90 | ||||||||||
Price per barrel | $ | 51.68 | (48 | ) | $ | 99.79 | (9 | ) | $ | 109.15 | |||||||
Total | |||||||||||||||||
Sales volumes—MMBbls | 116 | 9 | % | 106 | 18 | % | 91 | ||||||||||
MBbls/d | 317 | 9 | 292 | 18 | 248 | ||||||||||||
Price per barrel | $ | 46.79 | (49 | ) | $ | 91.58 | (10 | ) | $ | 101.41 | |||||||
Oil and condensate sales revenues (millions) | $ | 5,420 | (44 | ) | $ | 9,748 | 6 | $ | 9,178 | ||||||||
_______________________________________________________________________________
MMBbls—million barrels
Oil and Condensate Sales Volumes
2015 vs. 2014 Anadarko’s oil and condensate sales volumes increased by 25 MBbls/d.
• | Sales volumes in the Rockies increased by 11 MBbls/d primarily in the Wattenberg field due to continued horizontal drilling, partially offset by lower sales volumes due to the sale of certain EOR assets in April 2015. |
• | Sales volumes in the Southern and Appalachia Region increased by 10 MBbls/d primarily in the Eagleford shale as a result of continued horizontal drilling and in the Delaware basin due to wells brought online as a result of additional infrastructure and continued drilling. |
• | Sales volumes in the Gulf of Mexico increased by 8 MBbls/d primarily from the Lucius development achieving first oil in January 2015, partially offset by a natural production decline at Marco Polo. |
• | International sales volumes decreased by 4 MBbls/d primarily due to the timing of liftings in Algeria and the sale of the Company’s Chinese subsidiary in August 2014, partially offset by higher sales volumes due to the timing of liftings in Ghana. |
2014 vs. 2013 Anadarko’s oil and condensate sales volumes increased by 44 MBbls/d.
• | Sales volumes in the Rockies increased by 33 MBbls/d primarily in the Wattenberg field due to increased horizontal drilling. |
• | Sales volumes in the Southern and Appalachia Region increased by 15 MBbls/d, primarily as a result of increased horizontal drilling and 2013 infrastructure expansion in the Eagleford shale and increased horizontal drilling in the Delaware basin. |
• | International sales volumes decreased by 1 MBbls/d primarily due to lower sales volumes in China as a result of maintenance downtime and the sale of the Company’s Chinese subsidiary and the timing of liftings in Ghana, partially offset by higher sales volumes in Algeria from additional facilities and wells brought online at El Merk. |
• | Sales volumes in the Gulf of Mexico decreased by 1 MBbls/d primarily due to natural production declines. |
Oil and Condensate Prices
2015 vs. 2014 Anadarko’s average oil price received decreased primarily as a result of global oversupply.
2014 vs. 2013 Anadarko’s average oil price received decreased as a result of a global oversupply and reduced oil demand resulting from continued economic weakness particularly in late 2014.
57
Natural-Gas Sales Volumes, Average Prices, and Revenues
2015 | Inc/(Dec) vs. 2014 | 2014 | Inc/(Dec) vs. 2013 | 2013 | |||||||||||||
United States | |||||||||||||||||
Sales volumes—Bcf | 852 | (10 | )% | 945 | (2 | )% | 968 | ||||||||||
MMcf/d | 2,334 | (10 | ) | 2,589 | (2 | ) | 2,652 | ||||||||||
Price per Mcf | $ | 2.36 | (42 | ) | $ | 4.07 | 16 | $ | 3.50 | ||||||||
Natural-gas sales revenues (millions) | $ | 2,007 | (48 | ) | $ | 3,849 | 14 | $ | 3,388 | ||||||||
_______________________________________________________________________________
Bcf—billion cubic feet
MMcf/d—million cubic feet per day
Mcf—thousand cubic feet
Natural-Gas Sales Volumes
2015 vs. 2014 The Company’s natural-gas sales volumes decreased by 255 MMcf/d.
• | Sales volumes in the Southern and Appalachia Region decreased by 145 MMcf/d primarily due to voluntary curtailments and third-party infrastructure downtime in the Marcellus shale and the July 2015 sale of certain U.S. onshore properties and related midstream assets in East Texas. These decreases were partially offset by higher sales volumes as a result of continued horizontal drilling in the Eagleford shale. |
• | Sales volumes in the Rockies decreased by 66 MMcf/d primarily due to voluntary curtailments at Greater Natural Buttes, a natural production decline at Powder River basin, and the September 2015 sale of certain coalbed methane properties, partially offset by higher sales volumes in the Wattenberg field as a result of continued horizontal drilling. |
• | Sales volumes in the Gulf of Mexico decreased by 44 MMcf/d primarily due to a natural production decline at IHUB, partially offset by the Lucius development achieving first production in January 2015. |
2014 vs. 2013 The Company’s natural-gas sales volumes decreased by 63 MMcf/d.
• | Sales volumes in the Rockies decreased by 90 MMcf/d primarily due to the January 2014 sale of the Company’s Pinedale/Jonah assets and natural production declines in the Powder River basin and Greater Natural Buttes. These decreases were partially offset by higher sales volumes in the Wattenberg field due to increased horizontal drilling. |
• | Sales volumes in the Gulf of Mexico decreased by 67 MMcf/d primarily due to a natural production decline at IHUB. |
• | Sales volumes in the Southern and Appalachia Region increased by 94 MMcf/d primarily due to infrastructure expansions that allowed the Company to bring wells online in the Marcellus and Eagleford shales as well as continued horizontal drilling in the liquids-rich East Texas/North Louisiana horizontal development. |
Natural-Gas Prices
2015 vs. 2014 The average natural-gas price Anadarko received decreased primarily due to strong year-over-year production growth in the northeast United States and slightly lower weather-driven residential and commercial demand mainly in the first half of 2015.
2014 vs. 2013 The average natural-gas price Anadarko received increased primarily due to low industry natural-gas storage levels as a result of colder than average winter temperatures and the associated high residential heating demand in early 2014. In addition, natural-gas prices increased as a result of higher industrial natural-gas demand, reduced natural-gas imports from Canada, and continued strength in exports to Mexico.
58
Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues
2015 | Inc/(Dec) vs. 2014 | 2014 | Inc/(Dec) vs. 2013 | 2013 | |||||||||||||
United States | |||||||||||||||||
Sales volumes—MMBbls | 45 | 6 | % | 43 | 28 | % | 33 | ||||||||||
MBbls/d | 124 | 6 | 116 | 28 | 91 | ||||||||||||
Price per barrel | $ | 17.03 | (52 | ) | $ | 35.48 | (7 | ) | $ | 37.97 | |||||||
International | |||||||||||||||||
Sales volumes—MMBbls | 2 | 91 | % | 1 | NM | — | |||||||||||
MBbls/d | 6 | 91 | 3 | NM | — | ||||||||||||
Price per barrel | $ | 29.85 | (47 | ) | $ | 56.16 | NM | $ | — | ||||||||
Total | |||||||||||||||||
Sales volumes—MMBbls | 47 | 8 | % | 44 | 31 | % | 33 | ||||||||||
MBbls/d | 130 | 8 | 119 | 31 | 91 | ||||||||||||
Price per barrel | $ | 17.61 | (51 | ) | $ | 36.01 | (5 | ) | $ | 37.97 | |||||||
Natural-gas liquids sales revenues (millions) | $ | 833 | (47 | ) | $ | 1,572 | 25 | $ | 1,262 | ||||||||
_________________________________________________________________________
NM—not meaningful
NGLs Sales Volumes
NGLs sales represent revenues from the sale of products derived from the processing of Anadarko’s natural-gas production.
2015 vs. 2014 The Company’s NGLs sales volumes increased by 11 MBbls/d.
• | Sales volumes in the Rockies increased by 6 MBbls/d primarily in the Wattenberg field due to continued horizontal drilling and the Lancaster plant coming online in April 2014, partially offset by ethane rejection. |
• | International sales volumes increased by 3 MBbls/d as volumes increased in Algeria since the commencement of sales at the Company’s El Merk facility during 2014. |
2014 vs. 2013 The Company’s NGLs sales volumes increased by 28 MBbls/d.
• | Sales volumes in the Rockies increased by 16 MBbls/d primarily in the Wattenberg field due to increased horizontal drilling and the Lancaster plant coming online in April 2014. |
• | Sales volumes in the Southern and Appalachia Region increased by 10 MBbls/d primarily as a result of increased horizontal drilling and 2013 infrastructure expansion in the Eagleford shale. |
• | International sales volumes increased by 3 MBbls/d due to the commencement of sales at the Company’s El Merk facility in Algeria in 2014. |
NGLs Prices
2015 vs. 2014 Anadarko’s average NGLs price received decreased primarily due to decreased propane prices as a result of lower seasonal demand, higher NGLs production levels, and a related decline in oil prices.
2014 vs. 2013 Anadarko’s average NGLs price received decreased primarily due to lower prices for butanes and natural gasoline resulting from higher industry production levels and a related decline in oil prices.
59
Gathering, Processing, and Marketing
millions except percentages | 2015 | Inc/(Dec) vs. 2014 | 2014 | Inc/(Dec) vs. 2013 | 2013 | ||||||||||||
Gathering, processing, and marketing sales | $ | 1,226 | 2 | % | $ | 1,206 | 16 | % | $ | 1,039 | |||||||
Gathering, processing, and marketing expense | 1,054 | 2 | 1,030 | 19 | 869 | ||||||||||||
Total gathering, processing, and marketing, net | $ | 172 | (2 | ) | $ | 176 | 4 | $ | 170 | ||||||||
Gathering and processing sales includes revenue from the sale of NGLs and remaining residue gas extracted from natural gas purchased from third parties and processed by Anadarko as well as fee revenue earned by providing gathering, processing, compression, and treating services to third parties. Marketing sales include the margin earned from purchasing and selling third-party oil and natural gas. Gathering, processing, and marketing expense includes the cost of third-party natural gas purchased and processed by Anadarko as well as other operating and transportation expenses related to the Company’s costs to perform gathering, processing, and marketing activities.
2015 vs. 2014 Gathering, processing, and marketing, net decreased by $4 million. The decrease primarily resulted from lower processing revenues due to decreased commodity prices, partially offset by increased processing volumes related to the November 2014 acquisition of Nuevo Midstream, LLC and higher marketing margins.
2014 vs. 2013 Gathering, processing, and marketing, net increased by $6 million primarily due to higher gathering and processing revenue associated with higher volumes, increased natural-gas prices, and increased infrastructure, partially offset by higher processing and transportation expenses due to the increased volumes.
60
Gains (Losses) on Divestitures and Other, net
millions except percentages | 2015 | Inc/(Dec) vs. 2014 | 2014 | Inc/(Dec) vs. 2013 | 2013 | ||||||||||||
Gains (losses) on divestitures | $ | (1,022 | ) | (154 | )% | $ | 1,891 | NM | $ | (470 | ) | ||||||
Other | 234 | 15 | 204 | 11 | % | 184 | |||||||||||
Total gains (losses) on divestitures and other, net | $ | (788 | ) | (138 | ) | $ | 2,095 | NM | $ | (286 | ) | ||||||
Gains (losses) on divestitures and other, net includes gains (losses) on divestitures and other operating revenues, including hard-minerals royalties, earnings from equity investments, and other revenues.
2015
• | The Company recognized a loss of $538 million associated with the divestiture of certain coalbed methane properties and related midstream assets in the Rockies for net proceeds of $154 million after closing adjustments. |
• | The Company recognized a loss of $350 million associated with the divestiture of certain EOR assets in the Rockies, with a sales price of $703 million, for net proceeds of $675 million after closing adjustments. |
• | The Company recognized a loss of $110 million associated with the divestiture of certain oil and gas properties and related midstream assets in East Texas, with a sales price of $440 million, for net proceeds of $425 million after closing adjustments. |
• | The Company recognized income of $130 million related to the settlement of a royalty lawsuit associated with a property in the Gulf of Mexico. |
2014
• | The Company recognized a gain of $1.5 billion related to its divestiture of a 10% working interest in Offshore Area 1 in Mozambique for net proceeds of $2.64 billion. |
• | The Company recognized a gain of $510 million associated with the divestiture of its Chinese subsidiary for net proceeds of $1.075 billion. |
• | The Company recognized a gain of $237 million associated with the divestiture of its interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico, for net proceeds of $500 million. |
• | During the fourth quarter of 2014, Anadarko considered certain EOR assets in the Rockies to be held for sale and recognized a $456 million loss. At December 31, 2014, these assets were no longer considered held for sale as the volatility in the current commodity-price environment reduced the probability that these assets would be sold within the next year. |
2013
• | The Company recognized losses on assets held for sale of $704 million, primarily associated with the Pinedale/Jonah assets in Wyoming, which were sold in January 2014 for net proceeds of $581 million. |
• | The Company divested its interest in a soda ash joint venture for net proceeds of $310 million and recognized a gain of $140 million while retaining its royalty interest in soda ash mined by the joint venture from the Company’s Land Grant. Additional consideration may also be received based on future revenue of the joint venture. |
• | The Company recognized gains on divestitures of $94 million for certain U.S. oil and gas properties. |
See Note 3—Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on assets held for sale.
61
Costs and Expenses
2015 | Inc/(Dec) vs. 2014 | 2014 | Inc/(Dec) vs. 2013 | 2013 | |||||||||||||
Oil and gas operating (millions) | $ | 1,014 | (13 | )% | $ | 1,171 | 7 | % | $ | 1,092 | |||||||
Oil and gas operating—per BOE | 3.32 | (13 | ) | 3.81 | (1 | ) | 3.83 | ||||||||||
Oil and gas transportation (millions) | 1,117 | — | 1,116 | 14 | 981 | ||||||||||||
Oil and gas transportation—per BOE | 3.66 | 1 | 3.63 | 6 | 3.44 | ||||||||||||
_______________________________________________________________________________
BOE—barrels of oil equivalent
Oil and Gas Operating Expenses
2015 vs. 2014 Oil and gas operating expenses decreased by $157 million primarily due to lower expenses of $73 million as a result of divestitures, lower workover costs of $49 million as a result of reduced activity primarily in the Rockies and the Southern and Appalachia Region, and lower surface maintenance expenses of $21 million primarily in the Rockies. The related costs per BOE decreased by $0.49 as a result of lower costs.
2014 vs. 2013 Oil and gas operating expenses increased by $79 million primarily due to higher costs associated with increased sales volumes in the Rockies and the Southern and Appalachia Region and increased activity in the Gulf of Mexico. These increases were partially offset by lower expenses due to the sales of the Company’s Pinedale/Jonah assets and its Chinese subsidiary. The related costs per BOE decreased by $0.02 due to increased sales volumes, partially offset by the higher costs.
Oil and Gas Transportation Expenses
2015 vs. 2014 Oil and gas transportation expenses were relatively flat. Oil and gas transportation expenses per BOE increased by $0.03 primarily due to decreased sales volumes.
2014 vs. 2013 Oil and gas transportation expenses increased by $135 million primarily due to higher gas-gathering and transportation costs primarily attributable to higher volumes related to the growth in the Company’s U.S. onshore asset base. Oil and gas transportation expenses per BOE increased by $0.19 with the higher costs partially offset by increased sales volumes.
62
millions | 2015 | 2014 | 2013 | ||||||||
Exploration Expense | |||||||||||
Dry hole expense | $ | 1,052 | $ | 762 | $ | 556 | |||||
Impairments of unproved properties | 1,215 | 483 | 308 | ||||||||
Geological and geophysical expense | 168 | 168 | 208 | ||||||||
Exploration overhead and other | 209 | 226 | 257 | ||||||||
Total exploration expense | $ | 2,644 | $ | 1,639 | $ | 1,329 | |||||
2015 vs. 2014 Exploration expense increased by $1.0 billion.
Dry hole expense increased by $290 million.
• | The Company wrote off suspended exploratory well costs of $746 million in 2015, primarily related to Brazil where the Company does not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment and other considerations. |
• | The Company recognized $306 million due to unsuccessful drilling activities expensed in 2015 primarily in Colombia and the Gulf of Mexico. |
• | Anadarko recognized $762 million due to unsuccessful drilling activities expensed in 2014 associated with wells in the Gulf of Mexico, the Rockies, and Mozambique. |
Impairments of unproved properties increased by $732 million.
• | In 2015, the Company recognized a $935 million impairment of unproved Greater Natural Buttes properties and a $66 million impairment of an unproved Gulf of Mexico property as a result of lower commodity prices. |
• | Also in 2015, the Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter. |
• | In 2014, the Company recognized impairments of $302 million primarily related to lower oil prices, a reduction of reserves, and the expiration of certain leases in the Gulf of Mexico. |
• | Also in 2014, the Company recognized impairments of $50 million due to the decision not to pursue further drilling in Sierra Leone. |
• | The Company recognized impairments of $38 million in 2014 as a result of changes in the Company’s drilling plans for certain U.S. onshore oil and gas properties. |
2014 vs. 2013 Exploration expense increased by $310 million.
Dry hole expense increased by $206 million.
• | The Company recognized $762 million due to unsuccessful drilling activities expensed in 2014 associated with wells in the Gulf of Mexico, the Rockies, and Mozambique. |
• | The Company recognized $556 million due to unsuccessful drilling activities expensed in 2013 associated with wells in Kenya, Sierra Leone, and Côte d’Ivoire. |
Impairments of unproved properties increased by $175 million.
• | In 2014, the Company recognized impairments of $390 million in the Gulf of Mexico, Sierra Leone, and certain U.S. onshore oil and gas properties discussed above. |
• | In 2013, the Company recognized impairments of $89 million in China, $53 million in Brazil, and $53 million for a U.S. onshore property as a result of changes in the Company’s drilling plans. |
Geological and geophysical expense decreased by $40 million due to lower seismic purchases in the Gulf of Mexico during 2014.
63
millions except percentages | 2015 | Inc/(Dec) vs. 2014 | 2014 | Inc/(Dec) vs. 2013 | 2013 | ||||||||||||
General and administrative | $ | 1,176 | (11 | )% | $ | 1,316 | 21 | % | $ | 1,090 | |||||||
Depreciation, depletion, and amortization | 4,603 | 1 | 4,550 | 16 | 3,927 | ||||||||||||
Other taxes | 553 | (56 | ) | 1,244 | 16 | 1,077 | |||||||||||
Impairments | 5,075 | NM | 836 | 5 | 794 | ||||||||||||
Other operating expense | 271 | 64 | 165 | 85 | 89 | ||||||||||||
General and Administrative Expenses (G&A)
2015 vs. 2014 G&A expense decreased by $140 million primarily due to lower bonus plan expense and lower legal fees, partially offset by increased benefit plan expense.
2014 vs. 2013 G&A expense increased by $226 million primarily due to higher employee-related expenses of $152 million primarily associated with increased headcount and higher bonus plan expense. In addition, G&A expense increased due to higher legal expenses of $38 million primarily related to the third-party reimbursement of legal expenses associated with the Algeria exceptional profits tax settlement received in 2013 and legal fees related to Tronox as well as higher consulting fees of $15 million.
Depreciation, Depletion, and Amortization (DD&A)
2015 vs. 2014 DD&A expense increased by $53 million primarily due to costs associated with additional gathering and processing facilities and higher costs and sales volumes associated with Gulf of Mexico and U.S. onshore properties. These increases were partially offset by the impact of lower costs primarily due to the impairment of the Company’s Greater Natural Buttes oil and gas properties and lower expense related to revisions to asset retirement cost estimates for fully depreciated Gulf of Mexico wells.
2014 vs. 2013 DD&A expense increased by $623 million primarily due to higher sales volumes in 2014, increased asset retirement costs for wells in the Gulf of Mexico, and increased costs associated with additional gathering and processing facilities.
Other Taxes
2015 vs. 2014 Other taxes decreased by $691 million.
• | U.S. severance taxes decreased by $272 million, Algerian exceptional profits taxes decreased by $238 million, and ad valorem taxes decreased by $155 million. These decreases were primarily due to lower commodity prices. |
• | Chinese windfall profits tax decreased by $24 million as a result of the sale of the Company’s Chinese subsidiary in August 2014. |
2014 vs. 2013 Other taxes increased by $167 million.
• | Algerian exceptional profits taxes increased by $128 million attributable to higher oil sales volumes and the commencement of NGLs sales in 2014. |
• | U.S. onshore ad valorem taxes increased by $85 million attributable to increased activity related to U.S. onshore properties. |
• | Chinese windfall profits tax decreased by $47 million resulting from maintenance downtime in the first half of 2014 and the sale of the Company’s Chinese subsidiary in August 2014. |
64
Impairments
2015
• | The Company recognized impairments of $3.0 billion related to the Company’s Greater Natural Buttes oil and gas properties and $482 million for related midstream properties in the Rockies, $687 million for other U.S. onshore oil and gas properties primarily in the Southern and Appalachia Region, $557 million for other midstream properties primarily in the Rockies, and $349 million for oil and gas properties in the Gulf of Mexico, all due to lower forecasted commodity prices. |
Prolonged low or further declines in commodity prices, changes to the Company’s drilling plans in response to lower prices, increases in drilling or operating costs, or negative reserves revisions could result in additional impairments in future periods. See Note 5—Impairments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on impairments and Risk Factors under Item 1A of this Form 10-K for further discussion on the risks associated with oil, natural-gas, and NGLs prices.
2014
• | The Company recognized impairments of $545 million related to certain U.S. onshore oil and gas properties and $276 million related to certain oil and gas properties in the Gulf of Mexico that were impaired primarily due to lower forecasted commodity prices. |
2013
• | The Company recognized impairments of $562 million due to a reduction in estimated future net cash flows and downward revisions of reserves for certain Gulf of Mexico properties resulting from changes to the Company’s development plans. |
• | The Company recognized impairments of $142 million for certain U.S. onshore oil and gas properties and $49 million for related midstream assets due to downward revisions of reserves resulting from changes to the Company’s development plans. |
• | The Company recognized impairments of $30 million for certain midstream properties due to a reduction in estimated future cash flows. |
Other Operating Expense
2015 vs. 2014 Other operating expense increased by $106 million primarily due to an increase in legal accruals of $97 million and a $48 million expense in 2015 for the early termination of a drilling rig, partially offset by lower payments to surface owners of $20 million.
2014 vs. 2013 Other operating expense increased by $76 million primarily due to an increase in legal accruals of $49 million and $14 million of expenses in 2014 for the early termination of drilling rigs.
65
Other (Income) Expense
millions | 2015 | 2014 | 2013 | ||||||||
Interest Expense | |||||||||||
Current debt, long-term debt, and other | $ | 989 | $ | 973 | $ | 949 | |||||
Capitalized interest | (164 | ) | (201 | ) | (263 | ) | |||||
Total interest expense | $ | 825 | $ | 772 | $ | 686 | |||||
2015 vs. 2014 Interest expense increased by $53 million.
• | Interest expense on debt increased by $16 million primarily due to higher debt outstanding during 2015, partially offset by decreased debt amortization costs for the $5.0 billion senior secured revolving credit facility ($5.0 billion Facility) that was replaced in January 2015. |
• | Capitalized interest decreased by $37 million primarily due to the completion of the Lucius development and lower construction-in-progress balances for long-term capital projects in Brazil, partially offset by higher construction-in-progress balances for long-term capital projects primarily in Ghana. |
2014 vs. 2013 Interest expense increased by $86 million.
• | Interest expense increased $13 million due to increased long-term debt outstanding during 2014. |
• | Capitalized interest decreased by $62 million primarily due to lower construction-in-progress balances for the Mozambique liquefied natural gas project and the completion of certain U.S. pipeline projects in late 2013 and early 2014. |
millions | 2015 | 2014 | 2013 | ||||||||
(Gains) Losses on Derivatives, net | |||||||||||
(Gains) losses on commodity derivatives, net | $ | (367 | ) | $ | (589 | ) | $ | 141 | |||
(Gains) losses on interest-rate and other derivatives, net | 268 | 786 | (539 | ) | |||||||
Total (gains) losses on derivatives, net | $ | (99 | ) | $ | 197 | $ | (398 | ) | |||
(Gains) losses on derivatives, net represents the changes in fair value of the Company’s derivative instruments as a result of changes in commodity prices and interest rates as well as contract modifications. Anadarko enters into commodity derivatives to manage the risk of changes in the market prices for its anticipated sales of production. In addition, Anadarko also enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness to manage exposure to interest-rate changes. For additional information, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
66
millions | 2015 | 2014 | 2013 | ||||||||
Other (Income) Expense, net | |||||||||||
Interest income | $ | (13 | ) | $ | (26 | ) | $ | (19 | ) | ||
Other | 162 | 46 | 108 | ||||||||
Total other (income) expense, net | $ | 149 | $ | 20 | $ | 89 | |||||
2015 vs. 2014 Other expense, net increased by $129 million.
• | Losses associated with certain equity investments increased by $61 million as a result of lower commodity prices. |
• | Unfavorable changes in foreign currency gains/losses of $35 million were primarily associated with foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil. |
• | Environmental reserve accruals associated with properties previously acquired by Anadarko increased by $22 million. |
• | Interest income from short-term investments decreased by $13 million. |
2014 vs. 2013 Other expense, net decreased by $69 million.
• | In 2013, as a result of a Chapter 11 bankruptcy declaration by a third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of a production facility and related wells, which were previously sold to the third party. The Company accrued costs of $117 million during 2013 to decommission the production facility and related wells and recognized a $22 million increase in the estimated decommissioning costs in 2014. Anadarko has completed the decommissioning of the facility and expects to complete the remaining decommissioning of the wells in 2016. |
• | As a result of a prior acquisition, the Company recognized a restoration liability of $50 million in 2013 with respect to a landfill located in California for which the Company was notified that it is a potentially responsible party. |
• | The Company reversed the $56 million tax indemnification liability associated with the 2006 sale of the Company’s Canadian subsidiary in 2013. The indemnity was reversed as a result of certain changes to Canadian tax laws. |
millions | 2015 | 2014 | 2013 | ||||||||
Tronox-related contingent loss | $ | 5 | $ | 4,360 | $ | 850 | |||||
In April 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) entered into a settlement agreement for $5.15 billion, resolving all claims asserted in the Tronox Adversary Proceeding. This amount represents principal of approximately $3.98 billion plus 6% interest from the filing of the Adversary Proceeding on May 12, 2009, through April 3, 2014. In addition, the Company agreed to pay interest on that amount from April 3, 2014, through the payment of the settlement. In January 2015, the Company paid $5.2 billion after the settlement became effective. See Note 15—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
67
Income Tax Expense
millions except percentages | 2015 | 2014 | 2013 | ||||||||
Income tax expense (benefit) | $ | (2,877 | ) | $ | 1,617 | $ | 1,165 | ||||
Income (loss) before income taxes | (9,689 | ) | 54 | 2,106 | |||||||
Effective tax rate | 30 | % | 2,994 | % | 55 | % | |||||
The Company reported a loss before income taxes for the year ended December 31, 2015. As a result, items that ordinarily increase or decrease the tax rate will have the opposite effect. The decrease from the 35% U.S. federal statutory rate for the year ended December 31, 2015, was primarily attributable to the following:
• | tax impact from foreign operations |
• | non-deductible Algerian exceptional profits tax for Algerian income tax purposes |
• | net changes in uncertain tax positions |
• | dispositions of non-deductible goodwill |
The increase from the 35% U.S. federal statutory rate for the year ended December 31, 2014, was primarily attributable to the following:
• | net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding |
• | net changes in other uncertain tax positions |
• | non-deductible Algerian exceptional profits tax for Algerian income tax purposes |
• | tax impact from foreign operations |
The increase from the 35% U.S. federal statutory rate for the year ended December 31, 2013, was primarily attributable to the following:
• | tax impact from foreign operations |
• | non-deductible Algerian exceptional profits tax for Algerian income tax purposes |
• | deferred tax adjustments |
For additional information on income tax rates, see Note 12—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Net Income (Loss) Attributable to Noncontrolling Interests
millions except percentages | 2015 | 2014 | 2013 | ||||||||
Net income (loss) attributable to noncontrolling interests | $ | (120 | ) | $ | 187 | $ | 140 | ||||
Public ownership in WES, limited partnership interest | 55.1 | % | 55.0 | % | 56.4 | % | |||||
Public ownership in WGP, limited partnership interest | 12.7 | % | 11.7 | % | 9.0 | % | |||||
The net loss attributable to noncontrolling interests for 2015 was primarily a result of WES midstream asset impairments of $514 million due to a reduction in estimated future cash flows caused by the low commodity-price environment and resulting reduced producer drilling activity and related throughput. See Note 20—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
68
LIQUIDITY AND CAPITAL RESOURCES
millions except percentages | 2015 | 2014 | 2013 | ||||||||
Net cash provided by (used in) operating activities | $ | (1,877 | ) | $ | 8,466 | $ | 8,888 | ||||
Net cash provided by (used in) investing activities | (4,771 | ) | (6,472 | ) | (8,216 | ) | |||||
Net cash provided by (used in) financing activities | 220 | 1,675 | 623 | ||||||||
Total debt | 15,751 | 15,092 | 13,565 | ||||||||
Total equity | 15,457 | 22,318 | 23,650 | ||||||||
Debt to total capitalization ratio | 50.5 | % | 40.3 | % | 36.5 | % | |||||
Overview Anadarko believes that its cash on hand, anticipated operating cash flows, proceeds from expected asset monetizations, and available borrowing capacity will be sufficient to fund the Company’s projected 2016 operational and capital programs and continue to meet its other current obligations. The Company continuously monitors its liquidity needs, coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule, and evaluates available funding alternatives in light of current and expected conditions. The Company has a variety of funding sources available, including cash on hand, an asset portfolio that provides ongoing cash-flow-generating capacity, opportunities for liquidity enhancement through divestitures and joint-venture arrangements that reduce future capital expenditures, and the Company’s credit facilities and commercial paper program. In addition, an effective registration statement is available to Anadarko covering the sale of WGP common units owned by the Company.
Operating Activities
One of the primary sources of variability in the Company’s cash flows from operating activities is the fluctuation in commodity prices, the impact of which Anadarko partially mitigates by entering into commodity derivatives. Sales volume changes also impact cash flow, but historically have not been as volatile as commodity prices. Anadarko’s cash flows from operating activities are also impacted by the costs related to continued operations and debt service.
Anadarko’s cash flow used in operating activities in 2015 was $1.9 billion, compared to cash flows provided by operating activities of $8.5 billion in 2014 and $8.9 billion in 2013. The decrease in 2015 was primarily due to the $5.2 billion Tronox settlement payment, decreased sales revenues primarily resulting from lower commodity prices, and a net decrease in accounts payable and accrued expenses.
Cash flows from operating activities for 2014 decreased due to $730 million of cash received in 2013 associated with the Algeria exceptional profits tax settlement, a $520 million income tax payment in 2014 associated with the Company’s divestiture of a 10% working interest in Offshore Area 1 in Mozambique, lower average oil and NGLs prices, lower natural-gas volumes, higher operating expenses, and the unfavorable impact of changes in working capital items. These decreases were substantially offset by higher average natural-gas prices, higher sales volumes for oil and NGLs, and net cash received in settlement of commodity derivative instruments.
Tronox Settlement Payment In April 2014, Anadarko and Kerr-McGee entered into a settlement agreement to resolve all claims asserted in the Tronox Adversary Proceeding for $5.15 billion. In addition, the Company agreed to pay interest on that amount from April 3, 2014, through payment of the settlement, with an annual interest rate of 1.5% for the first 180 days and 1.5% plus the one-month LIBOR thereafter. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective using cash on hand and borrowings. See Note 15—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Pension and Other Postretirement Contributions Contributions to the pension and other postretirement plans were $58 million in 2015, $136 million in 2014, and $174 million in 2013. The Company expects to contribute $46 million in 2016 to its pension and other postretirement plans.
69
Investing Activities
Capital Expenditures The following presents the Company’s capital expenditures:
millions | 2015 | 2014 | 2013 | ||||||||
Cash Flows from Investing Activities | |||||||||||
Additions to properties and equipment and dry holes | $ | 6,067 | $ | 9,508 | $ | 7,721 | |||||
Adjustments for capital expenditures | |||||||||||
Changes in capital accruals | (226 | ) | (237 | ) | 246 | ||||||
Corporate acquisitions | — | — | 475 | ||||||||
Other | 47 | (15 | ) | 81 | |||||||
Total capital expenditures (1) | $ | 5,888 | $ | 9,256 | $ | 8,523 | |||||
_______________________________________________________________________________
(1) | Includes WES capital expenditures of $525 million in 2015, $696 million in 2014, and $792 million in 2013. |
During 2015, cash from operations and property divestitures were the primary sources for funding capital investments. The Company’s capital expenditures decreased by 36% for the year ended December 31, 2015, primarily due to reduced development and exploration activity, which resulted in decreased development costs of $2.1 billion primarily in the Rockies and the Southern and Appalachia Region; lower exploration costs of $710 million primarily in the Southern and Appalachia Region and the Gulf of Mexico; and lower gathering, processing, and other costs of $498 million primarily due to lower expenditures for plants and gathering in the Rockies. Development acquisitions in 2014 included a spar lease buyout of $110 million in the Gulf of Mexico. These decreases were partially offset by the 2015 acquisition of certain oil and gas properties in the Delaware basin for $79 million.
The Company’s capital expenditures increased by 9% for the year ended December 31, 2014, due to increased development costs primarily in the Wattenberg field of $663 million and in the Eagleford shale of $546 million and a spar lease buyout of $110 million in the Gulf of Mexico. The increase in the Eagleford shale was primarily due to the 2013 development drilling being funded by a third party as a result of a carried-interest agreement that was fully funded in June 2013. These 2014 increases were partially offset by 2013 acquisitions of certain oil and gas properties and related assets in the Moxa area of Wyoming for $310 million, primarily representing the fair value of the oil and gas properties acquired, and the acquisition of a 33.75% interest in gas-gathering systems located in the Marcellus shale in north-central Pennsylvania from a third party by WES for $135 million.
Carried-Interest Arrangements In 2014, the Company entered into a carried-interest arrangement that requires a third party to fund $442 million of Anadarko’s capital costs in exchange for a 34% working interest in the Eaglebine development, located in Southeast Texas. The third-party funding is expected to cover Anadarko’s future capital costs in the development through 2020. At December 31, 2015, $111 million of the $442 million carry obligation had been funded.
In 2013, the Company entered into a carried-interest arrangement that requires a third party to fund $860 million of Anadarko’s capital costs in exchange for a 12.75% working interest in the Heidelberg development, located in the Gulf of Mexico. At December 31, 2015, $793 million of the $860 million carry obligation had been funded.
Acquisitions of Businesses In November 2014, WES acquired Nuevo Midstream, LLC (Nuevo), which owns and operates gathering and processing assets located in the Delaware basin in West Texas, for $1.557 billion, including $30 million of cash acquired. Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Divestitures Anadarko received pretax sales proceeds related to property divestiture transactions of $1.4 billion in 2015, $5.0 billion in 2014, and $567 million in 2013. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
70
Investments Capital contributions for equity investments are included in Other, net under Investing Activities in the Company’s Consolidated Statement of Cash Flows. The Company made capital contributions for equity investments of $119 million in 2015 and $167 million in 2014, which were primarily associated with joint ventures for a gas processing plant, marine well containment, and pipelines. The Company made capital contributions for equity investments of $396 million in 2013, which were primarily associated with joint ventures to construct the Front Range Pipeline, the Texas Express Pipeline, and two fractionation trains in Mont Belvieu.
Financing Activities
Senior Notes The following summarizes the Company’s debt activity related to senior notes:
millions | 2015 | 2014 | 2013 | Description | |||||||||
Issuances | $ | 500 | $ | — | $ | — | WES 3.950% Senior Notes due 2025 | ||||||
— | 625 | — | 3.450% Senior Notes due 2024 | ||||||||||
— | 625 | — | 4.500% Senior Notes due 2044 | ||||||||||
— | 100 | 250 | WES 2.600% Senior Notes due 2018 | ||||||||||
— | 400 | — | WES 5.450% Senior Notes due 2044 | ||||||||||
Repayments | — | (500 | ) | — | 7.625% Senior Notes due 2014 | ||||||||
— | (275 | ) | — | 5.750% Senior Notes due 2014 | |||||||||
In 2015, net proceeds from the WES 3.950% Senior Notes were used to repay borrowings under WES’s five-year $1.2 billion senior unsecured revolving credit facility (RCF). In 2014, net proceeds from the 3.450% Senior Notes and 4.500% Senior Notes were used for general corporate purposes and net proceeds from the WES 2.600% Senior Notes and WES 5.450% Senior Notes were used to repay WES RCF borrowings and for general partnership purposes. In 2013, net proceeds from the WES 2.600% Senior Notes were used to repay WES RCF borrowings.
Revolving Credit Facilities In June 2014, Anadarko entered into a $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility) and a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). In January 2015, upon satisfaction of certain conditions, including the payment of the settlement related to the Tronox Adversary Proceeding, these facilities replaced the Company’s $5.0 billion Facility. In December 2015, the Company amended the Five-Year Facility to extend the maturity date to January 2021, and in January 2016, the Company replaced the 364-Day Facility with a new $2.0 billion 364-day senior unsecured revolving facility on identical terms that will mature in January 2017.
The following summarizes the Company’s debt activity related to revolving credit facilities:
millions | 2015 | 2014 | 2013 | Description | |||||||||
Borrowings | $ | 1,800 | $ | — | $ | — | 364-Day Facility | ||||||
1,500 | — | — | $5.0 billion Facility | ||||||||||
400 | 1,160 | 710 | WES RCF | ||||||||||
Repayments | (1,800 | ) | — | — | 364-Day Facility | ||||||||
(1,500 | ) | — | — | $5.0 billion Facility | |||||||||
(610 | ) | (650 | ) | (710 | ) | WES RCF | |||||||
Anadarko Credit Facilities During 2015, borrowings under the 364-Day Facility were primarily used to repay $1.5 billion of borrowings entered into in January 2015 under its $5.0 billion Facility, which were used for partial payment of the settlement related to the Tronox Adversary Proceeding and for general corporate purposes. At December 31, 2015, the Company had no outstanding borrowings under the Five-Year Facility or the 364-Day Facility and was in compliance with all covenants therein.
WES RCF During 2015, WES borrowings were primarily used for general partnership purposes, including the funding of capital expenditures. At December 31, 2015, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $300 million at an interest rate of 1.73%, had outstanding letters of credit of $6 million, and had available borrowing capacity of $894 million.
71
During 2014, WES borrowings were primarily used to partially fund its acquisitions of DBM and Anadarko’s interests in Texas Express Pipeline LLC, Texas Express Gathering LLC, and Front Range Pipeline LLC and for other general partnership purposes, including the funding of capital expenditures. During 2013, WES borrowings were primarily used to fund the 2013 acquisitions of an interest in certain gas-gathering systems located in the Marcellus shale in north-central Pennsylvania and an intrastate pipeline in southwestern Wyoming, and for other general partnership purposes, including the funding of capital expenditures.
For additional information on the Company’s revolving credit facilities, such as years of maturity, interest rates, and covenants, see Note 11—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Commercial Paper Program In January 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Company’s Five-Year Facility. The maturities of the commercial paper notes vary, but may not exceed 397 days. The commercial paper notes are sold under customary terms in the commercial paper market and are issued either at a discounted price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted price or interest amounts are dependent on market conditions and the ratings assigned to the commercial paper program by credit rating agencies at the time of issuance of the commercial paper notes. During 2015, the Company had net borrowings of $250 million, which remained outstanding at December 31, 2015, at a weighted-average interest rate of 0.98%. During 2015, maximum outstanding borrowings under the commercial paper program were $1.4 billion and the average borrowings outstanding were $773 million with a weighted-average interest rate of 0.57%. See Note 11—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.
Debt Maturities At December 31, 2015, Anadarko’s scheduled debt maturities during 2016 consisted of $1.750 billion 5.950% Senior Notes scheduled to mature in September, $250 million of borrowings under the commercial paper program, and $33 million related to the senior amortizing notes associated with the TEUs. Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $839 million at the next put date in October 2016.
The Company classified the 5.950% Senior Notes, the Zero Coupons, and the outstanding commercial paper notes as long-term debt on the Company’s Consolidated Balance Sheet at December 31, 2015, as Anadarko intends to refinance these obligations prior to or at maturity with new long-term debt issuances or by using the Five-Year Facility.
Anadarko may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market purchases, privately negotiated transactions, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions, and other factors. The amounts involved may be material.
At December 31, 2015, Anadarko’s scheduled 2017 debt maturities were $2.0 billion. For additional information on the Company’s debt instruments, such as transactions during the period, years of maturity, and interest rates, see Note 11—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Tangible Equity Units During 2015, Anadarko issued 9.2 million TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU is comprised of a prepaid equity purchase contract for WGP common units, subject to Anadarko’s right to elect to issue and deliver shares of Anadarko’s common stock in lieu of WGP common units, and a senior amortizing note due in June 2018, which bears interest at the rate of 1.50% per year. For additional information, see Note 10—Tangible Equity Units in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. During 2015, Anadarko repaid $16 million of senior amortizing notes associated with the TEUs.
72
Derivative Instruments The Company’s derivative instruments are subject to individually negotiated credit provisions that may require the Company or the counterparties to provide collateral of cash or letters of credit depending on the derivative portfolio valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered such as if the Company’s credit rating from major credit rating agencies declines to a level that is below investment grade. Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As of December 31, 2015, the Company provided cash collateral of $58 million on its interest-rate derivatives with an other-than-insignificant financing element. For additional information, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Common Stock Dividends Anadarko paid dividends to its common stockholders of $553 million in 2015, $505 million in 2014, and $274 million in 2013. The Company increased the quarterly dividend paid to common stockholders from $0.09 per share to $0.18 per share during the third quarter of 2013 and from $0.18 per share to $0.27 per share during the second quarter of 2014. In response to the current commodity-price environment, the Company decreased the quarterly dividend to $0.05 per share in February 2016. Anadarko has paid a dividend to its common stockholders quarterly since becoming a public company in 1986.
The amount of future dividends paid to Anadarko common stockholders is determined by the Board on a quarterly basis and is based on earnings, financial conditions, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors deemed relevant by the Board.
Equity Transactions Anadarko sold 2.3 million WGP common units to the public and raised net proceeds of $130 million in 2015, and sold approximately 6 million WGP common units to the public and raised net proceeds of $335 million in 2014. The proceeds for both periods were used for general corporate purposes.
During 2015, WES issued 874 thousand common units to the public under its continuous offering program, which allows the issuance of up to an aggregate of $500 million of WES common units, and raised net proceeds of $57 million. The remaining amount available under this program was $442 million of WES common units at December 31, 2015. During 2014, WES issued approximately 10 million common units to the public and raised net proceeds of $691 million. The proceeds were used to partially fund a portion of its DBM acquisition. WES used all the capacity to issue units under the $125 million continuous offering program as of the end of the third quarter of 2014. During 2013, WES issued approximately 12 million common units to the public, including the $125 million continuous offering program. These offerings raised net proceeds of $725 million, which were primarily used to repay outstanding RCF borrowings and for other general partnership purposes, including funding of WES’s capital expenditures.
Distributions to Noncontrolling Interest Owners WES distributed to its unitholders other than Anadarko and WGP an aggregate of $231 million in 2015, $175 million in 2014, and $130 million in 2013. WES has made quarterly distributions to its unitholders since its initial public offering (IPO) in the second quarter of 2008 and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.80 per common unit for the fourth quarter of 2015 (paid in February 2016).
WGP distributed to its unitholders other than Anadarko an aggregate of $37 million during 2015, $24 million in 2014, and $12 million in 2013. WGP has made quarterly distributions to its unitholders since its IPO in December 2012 and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.40375 per unit for the fourth quarter of 2015 (to be paid in February 2016).
73
Insurance Coverage and Other Indemnities
Anadarko maintains property and casualty insurance that includes coverage for physical damage to the Company’s properties, blowout/control of a well, restoration and redrill, sudden and accidental pollution, third-party liability, workers’ compensation and employers’ liability, and other risks. Anadarko’s insurance coverage includes deductibles that must be met prior to recovery. Additionally, the Company’s insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect the Company against liability or loss from all potential consequences and damages.
The Company’s current insurance coverage includes (a) $400 million per occurrence from Oil Insurance Limited (OIL) for physical damage to Anadarko’s properties on a replacement cost basis, blowout/control of well, restoration and redrill, and sudden and accidental pollution; (b) $700 million per occurrence from the commercial markets for the items described in item (a) above, which is in excess of the OIL coverage and which follows the form of OIL coverage with certain exceptions; (c) $400 million from the commercial markets, which scales to Anadarko’s working interest, for third-party liabilities, including sudden and accidental pollution and aviation liability; and (d) $275 million for aircraft liability (in addition to the third-party liability limits described in item (c) above). Anadarko does not carry significant coverage for loss of production income from any of the Company’s facilities or for any losses that result from the effects of a named windstorm.
The Company’s service agreements, including drilling contracts, generally indemnify Anadarko for injuries and death to employees of the service provider and subcontractors hired by the service provider as well as for property damage suffered by the service provider and its contractors. Also, these service agreements generally indemnify Anadarko for pollution originating from the equipment of any contractors or subcontractors hired by the service provider.
Off-Balance-Sheet Arrangements
Anadarko may enter into off-balance-sheet arrangements and transactions that can give rise to material off-balance-sheet obligations. The Company’s material off-balance-sheet arrangements and transactions include operating lease arrangements and undrawn letters of credit. In addition, the Company enters into other contractual agreements in the normal course of business for processing, treating, transportation, and storage of oil, natural gas, and NGLs as well as for other oil and gas activities as discussed below in Obligations. Other than the items discussed above, there are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Anadarko’s liquidity or availability of or requirements for capital resources.
74
Obligations
The following is a summary of the Company’s obligations at December 31, 2015:
Obligations by Period (1) | |||||||||||||||||||
millions | 2016 | 2017-2018 | 2019-2020 | 2021 and beyond | Total | ||||||||||||||
Total debt | |||||||||||||||||||
Principal—total borrowings at face value (2) | $ | 2,033 | $ | 2,516 | $ | 1,200 | $ | 11,563 | $ | 17,312 | |||||||||
Principal—capital lease obligation | — | — | 1 | 19 | 20 | ||||||||||||||
Investee entities’ debt (3) | — | — | — | 2,853 | 2,853 | ||||||||||||||
Interest on borrowings | 932 | 1,500 | 1,161 | 7,460 | 11,053 | ||||||||||||||
Interest on capital lease obligations | 2 | 3 | 4 | 13 | 22 | ||||||||||||||
Investee entities’ interest (3) | 50 | 144 | 173 | 2,351 | 2,718 | ||||||||||||||
Operating leases | |||||||||||||||||||
Drilling rig commitments | 739 | 834 | 215 | — | 1,788 | ||||||||||||||
Production platforms | 21 | 43 | 50 | 23 | 137 | ||||||||||||||
Other | 46 | 79 | 49 | 18 | 192 | ||||||||||||||
Oil and gas activities | 741 | 886 | 276 | 314 | 2,217 | ||||||||||||||
Asset retirement obligations | 309 | 128 | 304 | 1,318 | 2,059 | ||||||||||||||
Midstream and marketing activities | 1,114 | 2,137 | 1,996 | 2,612 | 7,859 | ||||||||||||||
Derivative liabilities (4) | 54 | 419 | 513 | 500 | 1,486 | ||||||||||||||
Uncertain tax positions, interest, and penalties (5) | 418 | 65 | — | 1,307 | 1,790 | ||||||||||||||
Environmental liabilities | 24 | 25 | 32 | 64 | 145 | ||||||||||||||
Other | — | 116 | — | — | 116 | ||||||||||||||
Total | $ | 6,483 | $ | 8,895 | $ | 5,974 | $ | 30,415 | $ | 51,767 | |||||||||
_______________________________________________________________________________
(1) | This table does not include litigation-related contingent liabilities or the Company’s pension and postretirement benefit obligations. See Note 15—Contingencies and Note 16—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
(2) | Includes the fully accreted principal amount of the Zero Coupons of approximately $2.4 billion as coming due after 2020. While the Zero Coupons do not mature until 2036, the outstanding Zero Coupons can be put to the Company each October, in whole or in part, for the then-accreted value. The Company could be required to repurchase the outstanding Zero Coupons at $839 million in October 2016 (the next potential put date). |
(3) | Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Company’s Consolidated Balance Sheets in other long-term liabilities—other for all periods presented. These notes payable provide for a variable rate of interest, reset quarterly. Therefore, future interest payments presented in the table above are estimated using the forward LIBOR rate curve. Further, the above table does not reflect the preferred return that Anadarko receives on its investment in these entities, which is also LIBOR-based, but with a lower margin than the margin on the associated notes payable. See Note 8—Equity-Method Investments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
(4) | Represents Anadarko’s gross derivative liability after taking into account the impacts of netting margin and collateral balances deposited with counterparties. See Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
(5) | See Note 12—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
75
Operating Leases Operating lease obligations include approximately $1.7 billion related to five offshore drilling vessels and $98 million related to certain contracts for U.S. onshore drilling rigs. Anadarko manages its access to rigs to support the execution of its drilling strategy over the next several years. Lease payments associated with the drilling of exploratory wells and development wells, net of amounts billed to partners, will initially be capitalized as a component of oil and gas properties, and either depreciated or impaired in future periods or written off as exploration expense. At December 31, 2015, the Company had $329 million in various commitments under non-cancelable operating lease agreements for production platforms and equipment, buildings, facilities, compressors, and aircraft. For additional information, see Note 14—Commitments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Oil and Gas Activities At December 31, 2015, Anadarko had various long-term contractual commitments pertaining to exploration, development, and production activities that extend beyond 2015. The Company has work-related commitments for, among other things, drilling wells, obtaining and processing seismic data, and fulfilling rig commitments. The preceding table includes long-term drilling and work-related commitments of $2.2 billion, comprised of approximately $1.5 billion related to the United States and $728 million related to international locations.
Asset Retirement Obligations Anadarko is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The majority of Anadarko’s asset retirement obligations (AROs) relate to the plugging of wells and the related abandonment of oil and gas properties. The Company’s AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.
Midstream and Marketing Activities Anadarko has entered into various processing, transportation, storage, and purchase agreements to access markets and provide flexibility to sell its oil, natural gas, and NGLs in certain areas.
Environmental Liabilities Anadarko is subject to various environmental-remediation and reclamation obligations arising from federal, state, tribal, and local laws and regulations. At December 31, 2015, the Company’s Consolidated Balance Sheet included a $145 million liability for remediation and reclamation obligations. The Company continually monitors the liability recorded and ongoing remediation and reclamation activities, and believes the amount recorded is appropriate. For additional information on environmental issues, see Risk Factors under Item 1A of this Form 10-K.
76
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with generally accepted accounting principles in the United States (GAAP) requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion of the Company’s significant accounting policies. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment. The selection, development, and disclosure of these estimates is discussed with the Company’s Audit Committee.
Proved Reserves
Anadarko estimates its proved oil and gas reserves according to the definition of proved reserves provided by the Securities and Exchange Commission and the Financial Accounting Standards Board. This definition includes oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, government regulations, etc. (at prices and costs as of the date the estimates are made). Prices include consideration of price changes provided only by contractual arrangements, and do not include adjustments based on expected future conditions. For reserves information, see Oil and Gas Properties and Activities—Proved Reserves under Items 1 and 2 of this Form 10-K and the Supplemental Information on Oil and Gas Exploration and Production Activities under Item 8 of this Form 10-K.
The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, development plans, reservoir performance, prices, economic conditions, and governmental restrictions as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date.
The quantities of estimated proved oil and gas reserves are a significant component of DD&A. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A and could result in property impairments. If the estimates of proved reserves used in the unit-of-production calculations had been lower by five percent across all properties, DD&A in 2015 would have increased by approximately $223 million.
Exploratory Costs
Under the successful efforts method of accounting, exploratory costs associated with a well discovering hydrocarbons are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. Therefore, at any point in time, the Company may have capitalized costs on its Consolidated Balance Sheets associated with exploratory wells that may be charged to exploration expense in future periods. See Note 6—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.
77
Fair Value
The Company estimates fair value of long-lived assets for impairment testing, reporting units for goodwill impairment testing when necessary, assets and liabilities acquired in a business combination or exchanged in non-monetary transactions, pension plan assets, and initial measurements of AROs. When the Company is required to measure fair value and there is not a market-observable price for the asset or liability or for a similar asset or liability, the Company uses the cost, income, or market valuation approaches depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk-adjusted discount rate. The market approach is based on management’s best assumptions regarding prices and other relevant information from market transactions involving comparable assets. Such evaluations involve significant judgment and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, future net cash flows, economic and regulatory climates, and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs, and other factors, and are consistent with assumptions used in the Company’s business plans and investment decisions.
Property Impairments
When circumstances indicate that proved oil and gas properties may be impaired, the expected undiscounted future net cash flows of the asset group are compared to the carrying amount of the asset. If the expected undiscounted future net cash flows, based on the Company’s estimate of future oil and natural-gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the carrying amount, the carrying amount is reduced to fair value. Fair value estimates require significant judgment and oil and natural-gas prices are a significant component of the fair-value estimate. Prices have exhibited significant volatility in the past, and the Company expects that volatility to continue in the future.
A long-lived asset other than an unproved oil and gas property is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may be greater than its undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value. The Company uses a variety of fair-value measurement techniques as discussed above when market information for the same or similar assets does not exist.
Goodwill Impairments
The Company tests goodwill for impairment annually in October (or more frequently as circumstances dictate). The Company first assesses whether an impairment of goodwill is indicated through a qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is less than its carrying amount, including goodwill. If the Company concludes it is more likely than not that fair value of the reporting unit exceeds the related carrying amount, then goodwill is not impaired and further testing is not necessary. If the qualitative assessment indicates fair value of the reporting unit may be less than its carrying amount, the Company compares the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill, and determines whether impairment is necessary.
When evaluating whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company assesses relevant events and circumstances, including the following:
• | significant changes in the stock price of Anadarko, WES, and WGP |
• | changes in commodity prices |
• | changes in cost factors such as costs of drilling; production costs; and gathering, processing, and other transportation costs |
• | impairments recognized by the Company |
• | acquisitions and disposals of assets |
78
• | changes to the Company’s reserves, including changes due to fluctuations in commodity prices and updates to the Company’s plans or forecasts |
• | changes in trading multiples for midstream peers |
Because quoted market prices for the Company’s reporting units are not available, management applies judgment in determining the estimated fair value of reporting units for purposes of performing goodwill impairment tests, when such tests are necessary. Management uses information available to make these fair-value estimates, including the present values of expected future cash flows using discount rates commensurate with the risks associated with the assets and observable for the oil and gas exploration and production reporting unit, control premiums and market multiples of earnings before interest, taxes, depreciation, and amortization (EBITDA) for the gathering and processing and transportation reporting units.
In estimating the fair value of its oil and gas exploration and production reporting unit, the Company assumes production profiles used in its estimation of reserves that are disclosed in the Company’s supplemental oil and gas disclosures, market prices based on the forward price curve for oil and gas at the test date (adjusted for location and quality differentials), capital and operating costs consistent with pricing and expected inflation rates, and discount rates that management believes a market participant would use based upon the risks inherent in Anadarko’s operations. Management also includes control premium assumptions based on observable market information regarding how a market participant would value the oil and gas exploration and production reporting unit as a whole rather than as individual properties that are part of an oil and gas portfolio.
The Company estimates fair value for the WES gathering and processing, WES transportation, and other gathering and processing reporting units by applying an estimated multiple to projected EBITDA. The Company considered observable transactions in the market and trading multiples for peers in determining an appropriate multiple to apply against the Company’s projected EBITDA for these reporting units.
A lower fair-value estimate in the future for any of these reporting units could result in impairment of goodwill. Factors that could trigger a lower fair-value estimate include prolonged low or further declines in commodity prices, decreases in proved reserves, changes in exploration or development plans, significant property impairments, increases in operating or drilling costs, significant changes in regulations, or other negative changes to the economic environment in which Anadarko operates.
Environmental Obligations and Other Contingencies
Management makes judgments and estimates when it establishes liabilities for environmental remediation, litigation, and other contingent matters. Estimates of litigation-related liabilities are based on the facts and circumstances of the individual case and on information currently available to the Company. The extent of information available varies based on the status of the litigation and the Company’s evaluation of the claim and legal arguments. In future periods, a number of factors could significantly change the Company’s estimate of litigation-related liabilities including discovery activities; briefings filed with the relevant court; rulings from the court made pre-trial, during trial, or at the conclusion of any trial; and similar cases involving other plaintiffs and defendants that may set or change legal precedent. As events unfold throughout the litigation process, the Company evaluates the available information and may consult with third-party legal counsel to determine whether liability accruals should be established or adjusted.
Estimates of environmental liabilities are based on a variety of factors, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change the Company’s estimate of environmental-remediation costs such as changes in laws and regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment, and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures that could arise related to environmental or other contingent matters and actual costs may vary significantly from the Company’s estimates. The Company’s in-house legal counsel and environmental personnel regularly assess contingent liabilities and, in certain circumstances, consult with third-party legal counsel or consultants to assist in the evaluation of the Company’s liability for these contingencies.
79
Income Taxes
The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of various tax jurisdictions throughout the world. The Company has recognized deferred tax assets and liabilities for temporary differences, operating losses, and tax-credit carryforwards. The Company routinely assesses the realizability of its deferred tax assets by analyzing the reversal periods of available net operating loss carryforwards and credit carryforwards, temporary differences in tax assets and liabilities, the availability of tax planning strategies, and estimates of future taxable income and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves and selling prices that are consistent with the Company’s internal business forecasts. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. The accruals for deferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant judgment by management and are reviewed and adjusted routinely based on changes in facts and circumstances. Although management considers its tax accruals adequate, material changes in these accruals may occur in the future, based on the progress of ongoing tax audits, changes in legislation, and resolution of pending tax matters.
RECENT ACCOUNTING DEVELOPMENTS
See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion of recent accounting developments affecting the Company.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. In addition, foreign-currency exchange-rate risk exists due to anticipated foreign-currency-denominated payments and receipts. These risks can affect revenues and cash flows, and the Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of commodity derivative instruments used by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Both exchange and over-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
COMMODITY-PRICE RISK The Company’s most significant market risk relates to prices for natural gas, oil, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant decline. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.
Derivative Instruments Held for Non-Trading Purposes The Company had derivative instruments in place to reduce the price risk associated with future production of 30 MMBbls of oil, 14 Bcf of natural gas, and 1 MMBbls of NGLs at December 31, 2015, with a net derivative asset position of $273 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $58 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $44 million. However, any cash received or paid to settle these derivatives would be substantially offset by the sales value of production covered by the derivative instruments.
80
Derivative Instruments Held for Trading Purposes At December 31, 2015, the Company had a net derivative asset position of $17 million on outstanding derivative instruments entered into for trading purposes. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.
For additional information regarding the Company’s marketing and trading portfolio, see Marketing Activities under Items 1 and 2 of this Form 10-K.
INTEREST-RATE RISK Borrowings under each of the 364-Day Facility, the Five-Year Facility, the commercial paper program, and WES’s RCF are subject to variable interest rates. The balance of Anadarko’s long-term debt on the Company’s Consolidated Balance Sheets has fixed interest rates. The Company has $2.9 billion of obligations based on the London Interbank Offered Rate (LIBOR) that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two non-controlled entities. These obligations give rise to minimal net interest-rate risk because coupons on the related preferred investments are also LIBOR-based. While a 10% change in LIBOR would not materially impact the Company’s interest cost, it would affect the fair value of outstanding fixed-rate debt.
At December 31, 2015, the Company had a net derivative liability position of $1.5 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would increase (decrease) the aggregate fair value of outstanding interest-rate swap agreements by $103 million. However, any change in the interest-rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with future debt issuances. For a summary of the Company’s outstanding interest-rate derivative positions, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
FOREIGN-CURRENCY EXCHANGE-RATE RISK Anadarko’s operating revenues are denominated in U.S. dollars, and the predominant portion of Anadarko’s capital and operating expenditures are also U.S.-dollar-denominated. Exposure to foreign-currency risk generally arises in connection with project-specific contractual arrangements and other commitments. Near-term foreign-currency-denominated expenditures are primarily in Colombian pesos, Mozambican meticais, British pounds sterling, and Brazilian reais.
The Company also has risk related to exchange-rate changes applicable to cash held in escrow pending final determination of the Company’s Brazilian tax liability for its 2008 divestiture of the Peregrino field offshore Brazil, which is currently under consideration by the Brazilian courts. See Note 15—Contingencies—Other Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. At December 31, 2015, cash of $86 million was held in escrow.
Management periodically engages in various risk-management activities to mitigate a portion of its exposure to foreign-currency exchange-rate risk. A 10% increase or decrease in the foreign-currency exchange rate would not materially impact the Company’s gain or loss related to foreign currency.
81
Item 8. Financial Statements and Supplementary Data
ANADARKO PETROLEUM CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page | |
82
ANADARKO PETROLEUM CORPORATION
REPORT OF MANAGEMENT
Management prepared, and is responsible for, the Consolidated Financial Statements and the other information appearing in this annual report. The Consolidated Financial Statements present fairly the Company’s financial condition, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its Consolidated Financial Statements, the Company includes amounts that are based on estimates and judgments that Management believes are reasonable under the circumstances. The Company’s financial statements have been audited by KPMG LLP, an independent registered public accounting firm appointed by the Audit Committee of the Board of Directors. Management has made available to KPMG LLP all of the Company’s financial records and related data, as well as the minutes of the stockholders’ and Directors’ meetings.
MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Anadarko’s internal control system was designed to provide reasonable assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015. This assessment was based on criteria established in the Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 2015, the Company’s internal control over financial reporting was effective based on those criteria.
KPMG LLP has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2015.
/s/ R. A. WALKER |
R. A. Walker Chairman, President and Chief Executive Officer |
/s/ ROBERT G. GWIN |
Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer |
February 17, 2016 |
83
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Anadarko Petroleum Corporation:
We have audited Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Anadarko Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Anadarko Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2015, and our report dated February 17, 2016 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP |
Houston, Texas |
February 17, 2016 |
84
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Anadarko Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three–year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 17, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP |
Houston, Texas |
February 17, 2016 |
85
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31, | |||||||||||
millions except per-share amounts | 2015 | 2014 | 2013 | ||||||||
Revenues and Other | |||||||||||
Oil and condensate sales | $ | 5,420 | $ | 9,748 | $ | 9,178 | |||||
Natural-gas sales | 2,007 | 3,849 | 3,388 | ||||||||
Natural-gas liquids sales | 833 | 1,572 | 1,262 | ||||||||
Gathering, processing, and marketing sales | 1,226 | 1,206 | 1,039 | ||||||||
Gains (losses) on divestitures and other, net | (788 | ) | 2,095 | (286 | ) | ||||||
Total | 8,698 | 18,470 | 14,581 | ||||||||
Costs and Expenses | |||||||||||
Oil and gas operating | 1,014 | 1,171 | 1,092 | ||||||||
Oil and gas transportation | 1,117 | 1,116 | 981 | ||||||||
Exploration | 2,644 | 1,639 | 1,329 | ||||||||
Gathering, processing, and marketing | 1,054 | 1,030 | 869 | ||||||||
General and administrative | 1,176 | 1,316 | 1,090 | ||||||||
Depreciation, depletion, and amortization | 4,603 | 4,550 | 3,927 | ||||||||
Other taxes | 553 | 1,244 | 1,077 | ||||||||
Impairments | 5,075 | 836 | 794 | ||||||||
Other operating expense | 271 | 165 | 89 | ||||||||
Total | 17,507 | 13,067 | 11,248 | ||||||||
Operating Income (Loss) | (8,809 | ) | 5,403 | 3,333 | |||||||
Other (Income) Expense | |||||||||||
Interest expense | 825 | 772 | 686 | ||||||||
(Gains) losses on derivatives, net | (99 | ) | 197 | (398 | ) | ||||||
Other (income) expense, net | 149 | 20 | 89 | ||||||||
Tronox-related contingent loss | 5 | 4,360 | 850 | ||||||||
Total | 880 | 5,349 | 1,227 | ||||||||
Income (Loss) Before Income Taxes | (9,689 | ) | 54 | 2,106 | |||||||
Income tax expense (benefit) | (2,877 | ) | 1,617 | 1,165 | |||||||
Net Income (Loss) | (6,812 | ) | (1,563 | ) | 941 | ||||||
Net income (loss) attributable to noncontrolling interests | (120 | ) | 187 | 140 | |||||||
Net Income (Loss) Attributable to Common Stockholders | $ | (6,692 | ) | $ | (1,750 | ) | $ | 801 | |||
Per Common Share | |||||||||||
Net income (loss) attributable to common stockholders—basic | $ | (13.18 | ) | $ | (3.47 | ) | $ | 1.58 | |||
Net income (loss) attributable to common stockholders—diluted | $ | (13.18 | ) | $ | (3.47 | ) | $ | 1.58 | |||
Average Number of Common Shares Outstanding—Basic | 508 | 506 | 502 | ||||||||
Average Number of Common Shares Outstanding—Diluted | 508 | 506 | 505 | ||||||||
Dividends (per Common Share) | $ | 1.08 | $ | 0.99 | $ | 0.54 | |||||
See accompanying Notes to Consolidated Financial Statements.
86
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years Ended December 31, | |||||||||||
millions | 2015 | 2014 | 2013 | ||||||||
Net Income (Loss) | $ | (6,812 | ) | $ | (1,563 | ) | $ | 941 | |||
Other Comprehensive Income (Loss) | |||||||||||
Adjustments for derivative instruments | |||||||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | 10 | 9 | 11 | ||||||||
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | (4 | ) | (3 | ) | (4 | ) | |||||
Total adjustments for derivative instruments, net of taxes | 6 | 6 | 7 | ||||||||
Adjustments for pension and other postretirement plans | |||||||||||
Net gain (loss) incurred during period | 49 | (405 | ) | 416 | |||||||
Income taxes on net gain (loss) incurred during period | (18 | ) | 149 | (152 | ) | ||||||
Prior service credit (cost) incurred during period | 89 | — | — | ||||||||
Income taxes on prior service credit (cost) incurred during period | (33 | ) | — | — | |||||||
Amortization of net actuarial (gain) loss to general and administrative expense | 63 | 27 | 132 | ||||||||
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense | (20 | ) | (9 | ) | (49 | ) | |||||
Amortization of net prior service (credit) cost to general and administrative expense | (4 | ) | — | 1 | |||||||
Income taxes on amortization of net prior service (credit) cost to general and administrative expense | 2 | — | — | ||||||||
Total adjustments for pension and other postretirement plans, net of taxes | 128 | (238 | ) | 348 | |||||||
Total | 134 | (232 | ) | 355 | |||||||
Comprehensive Income (Loss) | (6,678 | ) | (1,795 | ) | 1,296 | ||||||
Comprehensive income (loss) attributable to noncontrolling interests | (120 | ) | 187 | 140 | |||||||
Comprehensive Income (Loss) Attributable to Common Stockholders | $ | (6,558 | ) | $ | (1,982 | ) | $ | 1,156 | |||
See accompanying Notes to Consolidated Financial Statements.
87
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, | |||||||
millions | 2015 | 2014 | |||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | $ | 939 | $ | 7,369 | |||
Accounts receivable (net of allowance of $11 million and $7 million) | |||||||
Customers | 652 | 1,118 | |||||
Others | 1,817 | 1,409 | |||||
Other current assets | 574 | 603 | |||||
Total | 3,982 | 10,499 | |||||
Properties and Equipment | |||||||
Cost | 70,683 | 75,107 | |||||
Less accumulated depreciation, depletion, and amortization | 36,932 | 33,518 | |||||
Net properties and equipment | 33,751 | 41,589 | |||||
Other Assets | 2,350 | 2,310 | |||||
Goodwill and Other Intangible Assets | 6,331 | 6,569 | |||||
Total Assets | $ | 46,414 | $ | 60,967 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Accounts payable | $ | 2,850 | $ | 3,683 | |||
Current asset retirement obligations | 309 | 257 | |||||
Interest payable | 247 | 247 | |||||
Other taxes payable | 318 | 332 | |||||
Accrued expenses | 424 | 505 | |||||
Short-term debt | 33 | — | |||||
Tronox-related contingent liability | — | 5,210 | |||||
Total | 4,181 | 10,234 | |||||
Long-term Debt | 15,718 | 15,092 | |||||
Other Long-term Liabilities | |||||||
Deferred income taxes | 5,400 | 8,527 | |||||
Asset retirement obligations | 1,750 | 1,796 | |||||
Other | 3,908 | 3,000 | |||||
Total | 11,058 | 13,323 | |||||
Equity | |||||||
Stockholders’ equity | |||||||
Common stock, par value $0.10 per share (1.0 billion shares authorized, 528.3 million and 525.9 million shares issued) | 52 | 52 | |||||
Paid-in capital | 9,265 | 9,005 | |||||
Retained earnings | 4,880 | 12,125 | |||||
Treasury stock (20.0 million and 19.3 million shares) | (995 | ) | (940 | ) | |||
Accumulated other comprehensive income (loss) | (383 | ) | (517 | ) | |||
Total Stockholders’ Equity | 12,819 | 19,725 | |||||
Noncontrolling interests | 2,638 | 2,593 | |||||
Total Equity | 15,457 | 22,318 | |||||
Total Liabilities and Equity | $ | 46,414 | $ | 60,967 | |||
See accompanying Notes to Consolidated Financial Statements.
88
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
Total Stockholders’ Equity | |||||||||||||||||||||||||||
millions | Common Stock | Paid-in Capital | Retained Earnings | Treasury Stock | Accumulated Other Comprehensive Income (Loss) | Non- controlling Interests | Total Equity | ||||||||||||||||||||
Balance at December 31, 2012 | $ | 51 | $ | 8,230 | $ | 13,829 | $ | (841 | ) | $ | (640 | ) | $ | 1,253 | $ | 21,882 | |||||||||||
Net income (loss) | — | — | 801 | — | — | 140 | 941 | ||||||||||||||||||||
Common stock issued | 1 | 292 | — | — | — | — | 293 | ||||||||||||||||||||
Dividends—common stock | — | — | (274 | ) | — | — | — | (274 | ) | ||||||||||||||||||
Repurchase of common stock | — | — | — | (54 | ) | — | — | (54 | ) | ||||||||||||||||||
Subsidiary equity transactions | — | 107 | — | — | — | 554 | 661 | ||||||||||||||||||||
Distributions to noncontrolling interest owners | — | — | — | — | — | (156 | ) | (156 | ) | ||||||||||||||||||
Contributions from noncontrolling interest owners | — | — | — | — | — | 2 | 2 | ||||||||||||||||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | — | — | — | — | 7 | — | 7 | ||||||||||||||||||||
Adjustments for pension and other postretirement plans | — | — | — | — | 348 | — | 348 | ||||||||||||||||||||
Balance at December 31, 2013 | 52 | 8,629 | 14,356 | (895 | ) | (285 | ) | 1,793 | 23,650 | ||||||||||||||||||
Net income (loss) | — | — | (1,750 | ) | — | — | 187 | (1,563 | ) | ||||||||||||||||||
Common stock issued | — | 286 | — | — | — | — | 286 | ||||||||||||||||||||
Dividends—common stock | — | — | (505 | ) | — | — | — | (505 | ) | ||||||||||||||||||
Repurchase of common stock | — | — | — | (45 | ) | — | — | (45 | ) | ||||||||||||||||||
Subsidiary equity transactions | — | 90 | 24 | — | — | 829 | 943 | ||||||||||||||||||||
Distributions to noncontrolling interest owners | — | — | — | — | — | (216 | ) | (216 | ) | ||||||||||||||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | — | — | — | — | 6 | — | 6 | ||||||||||||||||||||
Adjustments for pension and other postretirement plans | — | — | — | — | (238 | ) | — | (238 | ) | ||||||||||||||||||
Balance at December 31, 2014 | 52 | 9,005 | 12,125 | (940 | ) | (517 | ) | 2,593 | 22,318 | ||||||||||||||||||
Net income (loss) | — | — | (6,692 | ) | — | — | (120 | ) | (6,812 | ) | |||||||||||||||||
Common stock issued | — | 209 | — | — | — | — | 209 | ||||||||||||||||||||
Dividends—common stock | — | — | (553 | ) | — | — | — | (553 | ) | ||||||||||||||||||
Repurchase of common stock | — | — | — | (55 | ) | — | — | (55 | ) | ||||||||||||||||||
Subsidiary equity transactions | — | 51 | — | — | — | 99 | 150 | ||||||||||||||||||||
Issuance of tangible equity units | — | — | — | — | — | 348 | 348 | ||||||||||||||||||||
Distributions to noncontrolling interest owners | — | — | — | — | — | (282 | ) | (282 | ) | ||||||||||||||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | — | — | — | — | 6 | — | 6 | ||||||||||||||||||||
Adjustments for pension and other postretirement plans | — | — | — | — | 128 | — | 128 | ||||||||||||||||||||
Balance at December 31, 2015 | $ | 52 | $ | 9,265 | $ | 4,880 | $ | (995 | ) | $ | (383 | ) | $ | 2,638 | $ | 15,457 | |||||||||||
See accompanying Notes to Consolidated Financial Statements.
89
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, | |||||||||||
millions | 2015 | 2014 | 2013 | ||||||||
Cash Flows from Operating Activities | |||||||||||
Net income (loss) | $ | (6,812 | ) | $ | (1,563 | ) | $ | 941 | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities | |||||||||||
Depreciation, depletion, and amortization | 4,603 | 4,550 | 3,927 | ||||||||
Deferred income taxes | (3,152 | ) | (105 | ) | 90 | ||||||
Dry hole expense and impairments of unproved properties | 2,267 | 1,245 | 864 | ||||||||
Impairments | 5,075 | 836 | 794 | ||||||||
(Gains) losses on divestitures, net | 1,022 | (1,891 | ) | 470 | |||||||
Total (gains) losses on derivatives, net | (100 | ) | 207 | (392 | ) | ||||||
Operating portion of net cash received (paid) in settlement of derivative instruments | 335 | 371 | 85 | ||||||||
Other | 320 | 327 | 246 | ||||||||
Changes in assets and liabilities | |||||||||||
Tronox-related contingent liability | (5,210 | ) | 4,360 | 850 | |||||||
(Increase) decrease in accounts receivable | (2 | ) | 103 | 719 | |||||||
Increase (decrease) in accounts payable and accrued expenses | (995 | ) | 97 | 148 | |||||||
Other items, net | 772 | (71 | ) | 146 | |||||||
Net cash provided by (used in) operating activities | (1,877 | ) | 8,466 | 8,888 | |||||||
Cash Flows from Investing Activities | |||||||||||
Additions to properties and equipment and dry hole costs | (6,067 | ) | (9,508 | ) | (7,721 | ) | |||||
Acquisition of businesses | (3 | ) | (1,527 | ) | (473 | ) | |||||
Divestitures of properties and equipment and other assets | 1,415 | 4,968 | 567 | ||||||||
Other, net | (116 | ) | (405 | ) | (589 | ) | |||||
Net cash provided by (used in) investing activities | (4,771 | ) | (6,472 | ) | (8,216 | ) | |||||
Cash Flows from Financing Activities | |||||||||||
Borrowings, net of issuance costs | 4,632 | 2,879 | 958 | ||||||||
Repayments of debt | (4,033 | ) | (1,425 | ) | (710 | ) | |||||
Financing portion of net cash paid in settlement of derivative instruments | (35 | ) | (222 | ) | — | ||||||
Increase (decrease) in outstanding checks | (23 | ) | 62 | (13 | ) | ||||||
Dividends paid | (553 | ) | (505 | ) | (274 | ) | |||||
Repurchase of common stock | (55 | ) | (45 | ) | (54 | ) | |||||
Issuance of common stock, including tax benefit on share-based compensation awards | 34 | 121 | 146 | ||||||||
Sale of subsidiary units | 187 | 1,026 | 724 | ||||||||
Issuance of tangible equity units — equity component | 348 | — | — | ||||||||
Distributions to noncontrolling interest owners | (282 | ) | (216 | ) | (156 | ) | |||||
Contributions from noncontrolling interest owners | — | — | 2 | ||||||||
Net cash provided by (used in) financing activities | 220 | 1,675 | 623 | ||||||||
Effect of Exchange Rate Changes on Cash | (2 | ) | 2 | (68 | ) | ||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (6,430 | ) | 3,671 | 1,227 | |||||||
Cash and Cash Equivalents at Beginning of Period | 7,369 | 3,698 | 2,471 | ||||||||
Cash and Cash Equivalents at End of Period | $ | 939 | $ | 7,369 | $ | 3,698 | |||||
See accompanying Notes to Consolidated Financial Statements.
90
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
1. Summary of Significant Accounting Policies
General Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of oil, condensate, natural gas, and natural gas liquids (NGLs), and in the marketing of anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of oil, natural gas, and NGLs. The Company also participates in the hard-minerals business through royalty arrangements. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.
Basis of Presentation The Consolidated Financial Statements have been prepared in conformity with generally accepted accounting principles in the United States (GAAP). The Consolidated Financial Statements include the accounts of Anadarko and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Anadarko has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets. Certain prior-period amounts have been reclassified to conform to the current-year presentation.
Use of Estimates The preparation of financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves; the value of properties and equipment; goodwill; intangible assets; asset retirement obligations; litigation liabilities; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
Level 1—Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities (for example, exchange-traded futures contracts for which parties are willing to transact at the exchange-quoted price).
Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3—Inputs that are not observable from objective sources such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement).
In determining fair value, the Company uses observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value.
91
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
1. Summary of Significant Accounting Policies (Continued)
In arriving at fair-value estimates, the Company uses relevant observable inputs available for the valuation technique employed. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based on the lowest level of input that is significant to the fair-value measurement. For Anadarko, recurring fair-value measurements are performed for interest-rate derivatives, commodity derivatives, and investments in trading securities.
The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable reported on the Company’s Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount the Company would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 11—Debt and Interest Expense, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments.
Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination or through a non-monetary exchange transaction, intangible assets, goodwill, asset retirement obligations, exit or disposal costs, and capital lease assets where the present value of lease payments is greater than the fair value of the leased asset.
Revenues The Company’s oil and condensate are sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers.
The Company recognizes sales revenues for oil and condensate, natural gas, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when product has been delivered to a pipeline or when a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.
Anadarko provides gathering, processing, treating, and transporting services pursuant to a variety of contracts. Under these arrangements, the Company receives fees, or retains a percentage of products or a percentage of the proceeds from the sale of products and recognizes revenue at the time services are performed or product is sold. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income.
Marketing margins related to the Company’s production are included in oil and condensate sales, natural-gas sales, and NGLs sales. Marketing margins related to sales of commodities purchased from third parties and gains and losses on derivatives related to such marketing activities are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income.
The Company enters into buy/sell arrangements related to the transportation of a portion of its oil production. Under these arrangements, barrels are sold to a third party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These transactions are reported on a net basis and included in oil and gas transportation in the Company’s Consolidated Statements of Income.
Cash Equivalents The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
92
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
1. Summary of Significant Accounting Policies (Continued)
Accounts Receivable and Allowance for Uncollectible Accounts The Company conducts credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers. Based on these analyses, the Company may require a standby letter of credit or a financial guarantee. The Company charges uncollectible accounts receivable against the allowance for uncollectible accounts when it determines collection will no longer be pursued.
Inventories Commodity inventories are stated at the lower of average cost or market.
Properties and Equipment Properties and equipment are stated at cost less accumulated depreciation, depletion, and amortization (DD&A). Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gain or loss is recognized in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income.
Oil and Gas Properties The Company applies the successful efforts method of accounting for oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are charged against earnings as incurred. If an exploratory well provides evidence to justify potential completion as a producing well, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas (generally in deepwater and international locations) depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
Acquisition costs of unproved properties are periodically assessed for impairment and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis (thereby establishing a valuation allowance) over the average lease terms at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense in the Company’s Consolidated Statements of Income.
93
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
1. Summary of Significant Accounting Policies (Continued)
Capitalized Interest For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity-method affiliates that are undergoing the construction of assets that have not commenced principle operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 11—Debt and Interest Expense.
Asset Retirement Obligations Asset retirement obligations (AROs) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value and is included in DD&A in the Company’s Consolidated Statements of Income. If estimated future costs of AROs change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. See Note 13—Asset Retirement Obligations.
Impairments Properties and equipment are reviewed for impairment when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value. See Note 5—Impairments.
Depreciation, Depletion, and Amortization Costs of drilling and equipping successful wells, costs to construct or acquire facilities other than offshore platforms, associated asset retirement costs, and capital lease assets used in oil and gas activities are depreciated using the unit-of-production (UOP) method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties and costs to construct or acquire offshore platforms and associated asset retirement costs, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Mineral properties are also depleted using the UOP method. All other properties are stated at historical acquisition cost, net of impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 40 years for buildings, and up to 47 years for gathering facilities.
94
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
1. Summary of Significant Accounting Policies (Continued)
Goodwill and Other Intangible Assets Anadarko has allocated goodwill to the following reporting units: oil and gas exploration and production; Western Gas Partners, LP (WES) gathering and processing; WES transportation; and other gathering and processing. Goodwill is subject to annual impairment testing in October (or more frequent testing as circumstances dictate). Anadarko’s goodwill impairment test first assesses qualitative factors to determine whether goodwill is impaired. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, the Company will then perform a quantitative goodwill impairment test. Changes in goodwill may result from, among other things, impairments, acquisitions, or divestitures. See Note 7—Goodwill and Other Intangible Assets.
Other intangible assets represent contractual rights obtained in connection with business combinations that had favorable contractual terms relative to market at the acquisition date as well as customer-related intangible assets, including customer relationships established by acquired contracts. Other intangible assets are amortized over their estimated useful lives and are assessed for impairment whenever impairment indicators are present. See Note 7—Goodwill and Other Intangible Assets.
Derivative Instruments Anadarko uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Derivatives are carried on the balance sheet at fair value and are included in other current assets, other assets, accrued expenses, or other long-term liabilities, depending on the derivative position and the expected timing of settlement, unless they satisfy the normal purchases and sales exception criteria. Where the Company has the contractual right and intends to net settle, derivative assets and liabilities are reported on a net basis.
Gains and losses on derivative instruments are recognized currently in earnings. Net losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings. See Note 9—Derivative Instruments.
Accounts Payable Accounts payable included liabilities of $365 million at December 31, 2015, and $388 million at December 31, 2014, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in applicable bank accounts. Changes in these liabilities are reflected in cash flows from financing activities.
Legal Contingencies The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for legal contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. If the Company determines that a loss is probable and cannot estimate a specific amount for that loss, but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 15—Contingencies.
95
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
1. Summary of Significant Accounting Policies (Continued)
Environmental Contingencies The Company is subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. Except for environmental contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses associated with environmental obligations when such losses are probable and reasonably estimable. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 15—Contingencies.
Noncontrolling Interests Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiaries and are presented as a component of equity. Changes in Anadarko’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. See Note 20—Noncontrolling Interests.
Income Taxes The Company files various U.S. federal, state, and foreign income tax returns. Deferred federal, state, and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). The Company uses the flow-through method to account for its investment tax credits. See Note 12—Income Taxes.
The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires all deferred tax assets and liabilities, including any related valuation allowance, to be presented in the balance sheet as noncurrent. The Company has elected to adopt this ASU early using a retrospective approach. As a result of adoption, the Company reclassified $722 million from other current assets to deferred income taxes for the year ended December 31, 2014. See Note 12—Income Taxes.
Share-Based Compensation The Company accounts for share-based compensation at fair value. The Company grants equity-classified awards, including stock options and non-vested equity shares (restricted stock awards and units). The Company may also grant equity-classified and liability-classified awards based on a comparison of the Company’s total shareholder return (TSR) to the TSR of a predetermined group of peer companies (performance units).
The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of Anadarko common stock. For other share-based compensation awards, fair value is determined using a Monte Carlo simulation.
The Company records compensation cost, net of estimated forfeitures, for share-based compensation awards over the requisite service period using the straight-line method. An adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the awards. For equity-classified share-based compensation awards, expense is recognized based on the grant-date fair value. For liability-classified share-based compensation awards, expense is recognized for those awards expected to ultimately be paid. The amount of expense reported for liability-classified awards is adjusted for fair-value changes so that the expense recognized for each award is equivalent to the amount to be paid. See Note 19—Share-Based Compensation.
96
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
1. Summary of Significant Accounting Policies (Continued)
Recently Issued Accounting Standards The FASB issued ASU 2016-01, Financial Instruments—Overall: Recognition and Measurement of Financial Assets and Financial Liabilities (Subtopic 825-10). This ASU amends existing requirements on the classification and measurement of financial instruments. Changes to the current requirements primarily affect the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. This ASU is effective for annual periods beginning in 2018 with early adoption of certain provisions permitted. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.
The FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30)—Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30)—Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption will result in a reclassification that will reduce other current assets and short-term debt by $1 million and reduce other assets and long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015, when included in future filings.
The FASB issued ASU 2015-02, Consolidation—Amendments to the Consolidation Analysis. This ASU amends existing requirements applicable to reporting entities that are required to evaluate consolidation of a legal entity under the variable interest entity (VIE) or voting interest entity models. The provisions will affect how limited partnerships and similar entities are assessed for consolidation, including an additional requirement that a limited partnership will be a VIE unless the limited partners have either substantive kick-out or participating rights over the general partner. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. The Company has evaluated the impact of the adoption of this ASU on its consolidated financial statements and determined that Western Gas Equity Partners, LP (WGP), and WES, publicly traded consolidated subsidiaries of the Company, meet the criteria for variable interest entities for which the Company is the primary beneficiary for accounting purposes. The adoption of this ASU will not have a material impact on the Company’s consolidated financial statements; however, the VIE disclosure requirements will begin to apply in 2016 for the Company’s interest in WGP and WES.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company is required to adopt the new standard in the first quarter of 2018 using one of two retrospective application methods, with early adoption permitted in 2017. The Company is continuing to evaluate the provisions of this ASU, and has not determined the impact this standard may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.
2. Inventories
The following summarizes the major classes of inventories included in other current assets at December 31:
millions | 2015 | 2014 | |||||
Oil | $ | 116 | $ | 133 | |||
Natural gas | 36 | 27 | |||||
NGLs | 64 | 83 | |||||
Total inventories | $ | 216 | $ | 243 | |||
97
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
3. Acquisitions, Divestitures, and Assets Held for Sale
Acquisitions In November 2014, WES acquired Nuevo Midstream, LLC (Nuevo), which owns and operates gathering and processing assets in the Delaware basin in West Texas, for $1.557 billion. Following the acquisition, WES changed the name of Nuevo to Delaware Basin Midstream, LLC (DBM). This acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. This acquisition aligns the Company’s gas gathering and processing capacity with future industry production growth plans in the Delaware basin. Preliminary fair-value measurements of assets acquired and liabilities assumed were finalized in the fourth quarter of 2015. There were no material changes to the fair value of assets acquired and liabilities assumed from the amounts included on the Company’s Consolidated Balance Sheet at December 31, 2014. The following summarizes the fair value of assets acquired and liabilities assumed at the acquisition date:
millions | ||||
Current assets | $ | 63 | ||
Properties and equipment | 467 | |||
Other intangible assets | 811 | |||
Accounts payable | (19 | ) | ||
Accrued expenses | (38 | ) | ||
Deferred income taxes | (1 | ) | ||
Asset retirement obligations | (9 | ) | ||
Goodwill | 283 | |||
Total assets acquired and liabilities assumed | $ | 1,557 | ||
Fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of properties and equipment is based on market and cost approaches. Intangible assets consist of customer contracts, the fair value of which was determined using an income approach. Deferred tax assets (liabilities) represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. All of the goodwill related to this acquisition is amortizable for tax purposes. The assets acquired and liabilities assumed are included within the midstream reporting segment.
Results of operations attributable to this acquisition are included in the Company’s Consolidated Statements of Income from the date acquired. The amounts of revenue and earnings included in the Company’s Consolidated Statement of Income for the year ended December 31, 2014, and the amounts of revenue and earnings that would have been recognized had the acquisition occurred on January 1, 2014, are not material to the Company’s Consolidated Statements of Income.
98
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
3. Acquisitions, Divestitures, and Assets Held for Sale (Continued)
Divestitures and Assets Held for Sale The following summarizes the proceeds received and gains (losses) recognized on divestitures for the years ended December 31:
millions | 2015 | 2014 | 2013 | ||||||||
Proceeds received | $ | 1,415 | $ | 4,968 | $ | 567 | |||||
Gains (losses) on divestitures, net | (1,022 | ) | 1,891 | (470 | ) | ||||||
2015
• | The Company sold certain coalbed methane properties and related midstream assets in the Rocky Mountains Region (Rockies) for net proceeds of $154 million, after closing adjustments, and recognized a loss of $538 million. These assets were included in the oil and gas exploration and production and midstream reporting segments. |
• | The Company sold certain U.S. onshore oil and gas properties and related midstream assets in East Texas, with a sales price of $440 million, for net proceeds of $425 million after closing adjustments, and recognized a loss of $110 million. These assets were included in the oil and gas exploration and production and midstream reporting segments. |
• | The Company sold certain enhanced oil recovery (EOR) assets in the Rockies, with a sales price of $703 million, for net proceeds of $675 million after closing adjustments, and recognized a loss of $350 million. These assets were included in the oil and gas exploration and production reporting segment. |
2014 Total proceeds and net gains on divestitures during 2014 primarily related to assets included in the oil and gas exploration and production reporting segment as follows:
• | The Company sold a 10% working interest in Offshore Area 1 in Mozambique for $2.64 billion and recognized a gain of $1.5 billion. |
• | The Company sold its Chinese subsidiary for $1.075 billion and recognized a gain of $510 million. |
• | The Company sold its interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico for $500 million, and recognized a gain of $237 million. |
• | The Company sold its interest in the Pinedale/Jonah assets in Wyoming for $581 million. |
• | During the fourth quarter of 2014, Anadarko considered certain EOR assets in the Rockies to be held for sale and recognized losses of $456 million. These assets were remeasured to their fair value using a market approach and Level 2 fair-value measurement. Volatility in the then-current commodity-price environment had reduced the probability that the assets would be sold within one year and the assets were therefore no longer considered held for sale at December 31, 2014. |
2013
• | The Company sold its interests in a soda ash joint venture and certain U.S. onshore and Indonesian oil and gas properties and recognized net gains of $234 million, primarily related to the Company’s divestiture of its interests in the soda ash joint venture and certain U.S. oil and gas properties included in the oil and gas exploration and production reporting segment. |
• | The Company recognized losses of $704 million primarily related to its Pinedale/Jonah assets included in the oil and gas exploration and production reporting segment considered to be held for sale at December 31, 2013. The sale of these assets closed in 2014 as discussed above. |
99
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
3. Acquisitions, Divestitures, and Assets Held for Sale (Continued)
Property Exchange In 2013, the Company exchanged certain oil and gas properties in the Wattenberg field with a third party. The properties exchanged were measured at the Company’s historical net cost with no gain or loss recognized. Anadarko paid $106 million in cash as part of the exchange, which is included as an addition to properties and equipment on the Company’s Consolidated Statement of Cash Flows for the year ended December 31, 2013.
4. Properties and Equipment
The following summarizes properties and equipment by segment at December 31:
millions | 2015 | 2014 | |||||
Oil and gas exploration and production (1) | $ | 59,389 | $ | 63,674 | |||
Midstream | 8,458 | 8,647 | |||||
Other | 2,836 | 2,786 | |||||
Gross properties and equipment | $ | 70,683 | $ | 75,107 | |||
Less accumulated depreciation, depletion, and amortization | 36,932 | 33,518 | |||||
Net properties and equipment | $ | 33,751 | $ | 41,589 | |||
__________________________________________________________________
(1) | Includes costs associated with unproved properties of $3.5 billion at December 31, 2015, and $5.1 billion at December 31, 2014. |
100
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
5. Impairments
Impairments of proved properties are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of proved properties and the related post-impairment fair values by segment at December 31:
2015 | 2014 | 2013 | |||||||||||||||||||||
millions | Impairment | Fair Value(1) | Impairment | Fair Value(1) | Impairment | Fair Value(1) | |||||||||||||||||
Oil and gas exploration and production | |||||||||||||||||||||||
Long-lived assets held for use | |||||||||||||||||||||||
U.S. onshore properties | $ | 3,684 | $ | 1,253 | $ | 545 | $ | 552 | $ | 142 | $ | 271 | |||||||||||
Gulf of Mexico properties | 349 | 65 | 276 | 223 | 562 | 242 | |||||||||||||||||
Cost-method investment (2) | 3 | 32 | 3 | 32 | 11 | 32 | |||||||||||||||||
Midstream | |||||||||||||||||||||||
Long-lived assets held for use | 1,039 | 212 | 12 | — | 79 | 36 | |||||||||||||||||
Total impairments | $ | 5,075 | $ | 1,562 | $ | 836 | $ | 807 | $ | 794 | $ | 581 | |||||||||||
__________________________________________________________________
(1) | Measured as of the impairment date using the income approach and Level 3 inputs. |
(2) | Represents the after-tax net investment. |
2015 Impairments In 2015, impairments were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties in the Rockies, other U.S. onshore oil and gas properties primarily in the Southern and Appalachia Region, other midstream properties primarily in the Rockies, and oil and gas properties in the Gulf of Mexico, all of which were impaired due to lower forecasted commodity prices.
2014 Impairments In 2014, certain U.S. onshore and Gulf of Mexico oil and gas properties were impaired primarily due to lower forecasted commodity prices.
2013 Impairments In 2013, certain Gulf of Mexico properties were impaired due to a reduction in estimated future net cash flows and downward revisions of reserves resulting from changes to the Company’s development plans. Also in 2013, certain U.S. onshore properties and related midstream assets were impaired due to downward revisions of reserves resulting from changes to the Company’s development plans. In addition, a midstream property was impaired during 2013 due to a reduction in estimated future cash flows.
Impairments of Unproved Properties Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. In 2015, the Company recognized a $935 million impairment of unproved Greater Natural Buttes properties and a $66 million impairment of an unproved Gulf of Mexico property as a result of lower commodity prices. Also in 2015, the Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.
101
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
5. Impairments (Continued)
Potential for Future Impairments During 2015, the Company recognized significant impairments of proved oil and gas and midstream properties and impairments of unproved oil and gas properties, primarily as a result of lower forecasted commodity prices and changes to the Company’s drilling plans. At December 31, 2015, the Company’s estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $2.2 billion indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that, if this depletion group becomes impaired in a future period, the Company could recognize non-cash impairments in that period in excess of $800 million. It is also reasonably possible that prolonged low or further declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in other additional impairments.
6. Suspended Exploratory Well Costs
The following summarizes the changes in suspended exploratory well costs at December 31 for each of the last three years. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.
millions | 2015 | 2014 | 2013 | ||||||||
Balance at January 1 | $ | 1,522 | $ | 2,232 | $ | 2,062 | |||||
Additions pending the determination of proved reserves | 461 | 421 | 848 | ||||||||
Divestitures and other (1) | (33 | ) | (913 | ) | (48 | ) | |||||
Reclassifications to proved properties | (104 | ) | (100 | ) | (507 | ) | |||||
Charges to exploration expense (2) | (722 | ) | (118 | ) | (123 | ) | |||||
Balance at December 31 | $ | 1,124 | $ | 1,522 | $ | 2,232 | |||||
__________________________________________________________________
(1) | Includes $(744) million during 2014 related to the Company’s sale of a 10% working interest in Offshore Area 1 in Mozambique. |
(2) | Includes $(565) million during 2015 related to Brazil. Given the current oil-price environment and other considerations, the Company does not expect to have substantive exploration and development activities in Brazil in the foreseeable future. |
The following provides an aging of suspended well balances at December 31:
millions | 2015 | 2014 | 2013 | ||||||||
Exploratory well costs capitalized for a period of one year or less | $ | 452 | $ | 393 | $ | 836 | |||||
Exploratory well costs capitalized for a period greater than one year | 672 | 1,129 | 1,396 | ||||||||
Balance at December 31 | $ | 1,124 | $ | 1,522 | $ | 2,232 | |||||
102
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
6. Suspended Exploratory Well Costs (Continued)
The following summarizes a further aging by geographic area of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling at December 31, 2015:
millions except projects | Number of Projects | Total | 2014 | 2013 | 2012 and prior | ||||||||||||
United States—Onshore | 18 | $ | 55 | $ | 34 | $ | 11 | $ | 10 | ||||||||
United States—Offshore | 4 | 314 | 77 | 80 | 157 | ||||||||||||
International | 7 | 303 | 119 | 3 | 181 | ||||||||||||
29 | $ | 672 | $ | 230 | $ | 94 | $ | 348 | |||||||||
Projects with suspended exploratory well costs are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development and where management is actively pursuing efforts to assess whether reserves can be attributed to these projects. Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling at December 31, 2015, primarily related to the Gulf of Mexico, Ghana, and Mozambique.
For projects located in the Gulf of Mexico, the majority of exploratory well costs capitalized greater than one year are related to the Shenandoah discovery. Well costs have been suspended pending further appraisal activities, including drilling and analysis of well results. Appraisal activities undertaken at the Shenandoah discovery include the acquisition of whole-core across the primary reservoir interval, the processing and analysis of seismic data, reservoir simulation modeling, and analysis of well results. Remaining activities required to classify the associated reserves as proved for the Shenandoah discovery include completion of geologic, reservoir, and economic modeling; product development testing; and pre-front-end engineering and design (FEED) and FEED engineering studies.
For projects located in Ghana, exploratory well costs that have been capitalized greater than one year are pending development plan approval. During the fourth quarter of 2015, the Company and its partners submitted the Jubilee full field development plan for the Mahogany East and Teak areas. Remaining activities required to classify the associated reserves as proved include approval of development plans and project sanctioning.
For projects located in Mozambique, the majority of exploratory well costs capitalized greater than one year are related to the Orca, Tubarão, and Tubarão Tigre discoveries. Well costs have been suspended pending further appraisal activities, including analysis of well results and seismic reprocessing. During 2015, drilling and evaluation operations at the Tubarão Tigre-2 appraisal well were completed. Anadarko is continuing to appraise the Orca, Tubarão, and Tubarão Tigre discoveries in accordance with the appraisal programs provided to the government of Mozambique in the first quarter of 2015.
If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.
103
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
7. Goodwill and Other Intangible Assets
Goodwill At December 31, 2015, the Company had $5.4 billion of goodwill allocated to the following reporting units: $4.9 billion to oil and gas exploration and production, $383 million to WES gathering and processing, $5 million to WES transportation, and $62 million to other gathering and processing. The Company’s 2015 annual impairment assessment of goodwill indicated no impairment. An additional assessment was also performed in December 2015 to consider the impact of commodity-price changes since the annual test. This assessment also indicated no impairment.
Although commodity prices declined during the year, as of December 31, 2015, the estimated fair value of the oil and gas reporting unit exceeded the carrying value by more than 15%, without consideration for any control premium, and the other reporting units were not at risk of impairment. However, prolonged low or further declines in commodity prices, decreases in proved reserves, changes in exploration or development plans, significant property impairments, increases in operating or drilling costs, significant changes in regulations, or other negative changes to the economic environment in which Anadarko operates, could result in further goodwill impairment tests in the near term, the results of which may have a material adverse impact on the Company’s results of operations.
Other Intangible Assets Intangible assets and associated amortization expense were as follows:
millions | Gross Carrying Amount | Accumulated Amortization | Net Carrying Amount | Amortization Expense | |||||||||||
December 31, 2015 | |||||||||||||||
Offshore platform leases | $ | 33 | $ | (31 | ) | $ | 2 | $ | 2 | ||||||
Customer contracts | 980 | (46 | ) | 934 | 31 | ||||||||||
$ | 1,013 | $ | (77 | ) | $ | 936 | $ | 33 | |||||||
December 31, 2014 | |||||||||||||||
Offshore platform leases | $ | 33 | $ | (29 | ) | $ | 4 | $ | — | ||||||
Customer contracts | 1,004 | (15 | ) | 989 | 6 | ||||||||||
$ | 1,037 | $ | (44 | ) | $ | 993 | $ | 6 | |||||||
Customer contract intangible assets are primarily related to WES’s DBM acquisition in 2014. These contracts are being amortized over 30 years. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale. The annual aggregate amortization expense for intangible assets is expected to be $31 million each of the next five years.
104
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
8. Equity-Method Investments
In 2007, Anadarko contributed certain of its oil and gas properties and gathering and processing assets, with an aggregate fair value of $2.9 billion at the time of the contribution, to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable London Interbank Offered Rate (LIBOR) based preferred interests in those entities. The common equity of the investee entities is 95% owned by third parties that also maintain control over the assets. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion. The Company accounts for its investment in these entities using the equity method of accounting. The carrying amount of these investments was $2.8 billion and the carrying amount of notes payable to affiliates was $2.9 billion at December 31, 2015. Anadarko has legal right of setoff and intends to net settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Company’s Consolidated Balance Sheets in other long-term liabilities—other for all periods presented.
Interest on the notes issued by Anadarko is variable, and is equivalent to LIBOR plus a spread that fluctuates with Anadarko’s credit rating. The applicable interest rate was 1.51% at December 31, 2015, and 1.24% at December 31, 2014. The note payable agreement contains a covenant that provides for a maximum Anadarko debt-to-capital ratio of 67% (excluding the effect of non-cash write-downs). Anadarko was in compliance with this covenant at December 31, 2015. Other (income) expense, net includes interest expense on the notes payable of $37 million in 2015, $36 million in 2014, and $37 million in 2013, and equity (earnings) losses from Anadarko’s investments in the investee entities of $15 million in 2015, $(45) million in 2014, and $(42) million in 2013.
9. Derivative Instruments
Objective and Strategy The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations such as Henry Hub, Louisiana for natural gas and Cushing, Oklahoma or Sullom Voe, Scotland for oil. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).
Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio increases (decreases) when interest rates increase (decrease).
The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. See Note 18—Accumulated Other Comprehensive Income (Loss).
105
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
9. Derivative Instruments (Continued)
Oil and Natural-Gas Production/Processing Derivative Activities The oil prices listed below are a combination of New York Mercantile Exchange (NYMEX) West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The natural-gas prices listed below are NYMEX Henry Hub prices. The NGLs prices listed below are Oil Price Information Services prices (OPIS). The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at December 31, 2015:
2016 Settlement | ||||
Oil | ||||
Three-Way Collars (MBbls/d) | 83 | |||
Average price per barrel | ||||
Ceiling sold price (call) | $ | 63.82 | ||
Floor purchased price (put) | $ | 54.46 | ||
Floor sold price (put) | $ | 42.77 | ||
Natural Gas | ||||
Fixed-Price Contracts (thousand MMBtu/d) | 38 | |||
Average price per MMBtu | $ | 2.53 | ||
NGLs | ||||
Fixed-Price Contracts (MBbls/d) | 4 | |||
Average price per barrel | $ | 13.07 | ||
__________________________________________________________________
MMBtu—million British thermal units
MMBtu/d—million British thermal units per day
A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.
In 2014, the Company terminated or offset then-existing 2015 oil three-way collars with a notional volume of 25 thousand barrels per day due to lower oil prices, resulting in a cash receipt of $126 million.
Marketing and Trading Derivative Activities The Company had financial derivative transactions with notional volumes of natural gas totaling 8 billion cubic feet (Bcf) at December 31, 2015, and 6 Bcf at December 31, 2014, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.
106
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
9. Derivative Instruments (Continued)
Interest-Rate Derivatives Anadarko has outstanding interest-rate swap contracts to manage interest-rate risk associated with anticipated debt issuances. The Company has locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR.
In 2015, the Company extended the reference-period start dates on interest-rate swaps with an aggregate notional principal amount of $1.0 billion to align the portfolio with anticipated debt refinancing. The Company also amended the mandatory termination dates on interest-rate swaps with an aggregate notional principal amount of $1.8 billion so that, at the start of the reference period, Anadarko will receive quarterly payments based on the floating rate and make semi-annual payments based on the fixed interest rate. The interest-rate swaps are required to be settled in full at the mandatory termination date. As part of these interest-rate swap modifications, the fixed interest rates on the swaps were also adjusted, and the Company recognized a loss of $137 million, which is included in gains (losses) on derivatives, net in the Company’s Consolidated Statement of Income, and increased the related derivative liability. In 2014, in anticipation of the July 2014 issuance of an aggregate $1.25 billion of Senior Notes, interest-rate swap agreements with an aggregate notional principal amount of $750 million were settled in 2014, resulting in a cash payment of $222 million.
Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. As a result of prior extensions of reference-period start dates without settlement of the related interest-rate derivative obligations, the interest-rate derivatives in the Company’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements or collateralization related to these extended interest-rate derivatives are classified as cash flows from financing activities.
The Company had the following outstanding interest-rate swaps at December 31, 2015:
millions except percentages | Mandatory | Weighted-Average | |||||||
Notional Principal Amount | Reference Period | Termination Date | Interest Rate | ||||||
$ | 50 | September 2016 – 2026 | September 2016 | 5.910% | |||||
$ | 50 | September 2016 – 2046 | September 2016 | 6.290% | |||||
$ | 250 | September 2016 – 2046 | September 2018 | 6.310% | |||||
$ | 300 | September 2016 – 2046 | September 2020 | 6.509% | |||||
$ | 250 | September 2016 – 2046 | September 2021 | 6.724% | |||||
$ | 200 | September 2017 – 2047 | September 2018 | 6.049% | |||||
$ | 300 | September 2017 – 2047 | September 2020 | 6.569% | |||||
$ | 500 | September 2017 – 2047 | September 2021 | 6.654% | |||||
107
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
9. Derivative Instruments (Continued)
Effect of Derivative Instruments—Balance Sheet The following summarizes the fair value of the Company’s derivative instruments at December 31:
millions | Gross Derivative Assets | Gross Derivative Liabilities | ||||||||||||||
Balance Sheet Classification | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Commodity derivatives | ||||||||||||||||
Other current assets | $ | 462 | $ | 421 | $ | (177 | ) | $ | (118 | ) | ||||||
Other assets | 8 | 1 | — | — | ||||||||||||
Accrued expenses | — | 71 | (3 | ) | (114 | ) | ||||||||||
Other liabilities | — | — | — | (6 | ) | |||||||||||
470 | 493 | (180 | ) | (238 | ) | |||||||||||
Interest-rate derivatives | ||||||||||||||||
Other current assets | 2 | — | — | — | ||||||||||||
Other assets | 54 | — | — | — | ||||||||||||
Accrued expenses | — | — | (54 | ) | — | |||||||||||
Other liabilities | — | — | (1,488 | ) | (1,217 | ) | ||||||||||
56 | — | (1,542 | ) | (1,217 | ) | |||||||||||
Total derivatives | $ | 526 | $ | 493 | $ | (1,722 | ) | $ | (1,455 | ) | ||||||
Effect of Derivative Instruments—Statement of Income The following summarizes gains and losses related to derivative instruments:
millions | ||||||||||||
Classification of (Gain) Loss Recognized | 2015 | 2014 | 2013 | |||||||||
Commodity derivatives | ||||||||||||
Gathering, processing, and marketing sales (1) | $ | (1 | ) | $ | 10 | $ | 6 | |||||
(Gains) losses on derivatives, net | (367 | ) | (589 | ) | 141 | |||||||
Interest-rate derivatives | ||||||||||||
(Gains) losses on derivatives, net | 268 | 786 | (539 | ) | ||||||||
Total (gains) losses on derivatives, net | $ | (100 | ) | $ | 207 | $ | (392 | ) | ||||
__________________________________________________________________
(1) | Represents the effect of Marketing and Trading Derivative Activities. |
108
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
9. Derivative Instruments (Continued)
Credit-Risk Considerations The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on the fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure.
The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types. At December 31, 2015, $347 million of the Company’s $1.722 billion gross derivative liability balance, and at December 31, 2014, $289 million of the Company’s $1.455 billion gross derivative liability balance would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.
The Company’s derivative instruments are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s valuation versus negotiated credit thresholds. These credit thresholds may also require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered such as if the Company’s credit rating from major credit rating agencies declines to a level that is below investment grade. Previously, most of the Company’s derivative counterparties maintained secured positions with respect to the Company’s derivative liabilities under the Company’s $5.0 billion senior secured revolving credit facility ($5.0 billion Facility). In January 2015, the Company’s $5.0 billion Facility was replaced by new unsecured facilities under which the Company’s derivative counterparties no longer maintain security interests in any of the Company’s assets. As a result, the Company may be required from time to time to post collateral of cash or letters of credit based on the negotiated terms of the individual derivative agreements. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.3 billion (net of collateral) at December 31, 2015, and $97 million (net of collateral) at December 31, 2014. For information on the Company’s revolving credit facilities, see Note 11—Debt and Interest Expense—Anadarko Revolving Credit Facilities and Commercial Paper Program.
109
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
9. Derivative Instruments (Continued)
Fair Value Fair value of futures contracts is based on unadjusted quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.
The following summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:
millions | Level 1 | Level 2 | Level 3 | Netting (1) | Collateral | Total | |||||||||||||||||
December 31, 2015 | |||||||||||||||||||||||
Assets | |||||||||||||||||||||||
Commodity derivatives | $ | 10 | $ | 460 | $ | — | $ | (178 | ) | $ | (8 | ) | $ | 284 | |||||||||
Interest-rate derivatives | — | 56 | — | — | — | 56 | |||||||||||||||||
Total derivative assets | $ | 10 | $ | 516 | $ | — | $ | (178 | ) | $ | (8 | ) | $ | 340 | |||||||||
Liabilities | |||||||||||||||||||||||
Commodity derivatives | $ | (1 | ) | $ | (179 | ) | $ | — | $ | 178 | $ | — | $ | (2 | ) | ||||||||
Interest-rate derivatives | — | (1,542 | ) | — | — | 58 | (1,484 | ) | |||||||||||||||
Total derivative liabilities | $ | (1 | ) | $ | (1,721 | ) | $ | — | $ | 178 | $ | 58 | $ | (1,486 | ) | ||||||||
December 31, 2014 | |||||||||||||||||||||||
Assets | |||||||||||||||||||||||
Commodity derivatives | $ | — | $ | 493 | $ | — | $ | (189 | ) | $ | (13 | ) | $ | 291 | |||||||||
Total derivative assets | $ | — | $ | 493 | $ | — | $ | (189 | ) | $ | (13 | ) | $ | 291 | |||||||||
Liabilities | |||||||||||||||||||||||
Commodity derivatives | $ | — | $ | (238 | ) | $ | — | $ | 189 | $ | — | $ | (49 | ) | |||||||||
Interest-rate derivatives | — | (1,217 | ) | — | — | 23 | (1,194 | ) | |||||||||||||||
Total derivative liabilities | $ | — | $ | (1,455 | ) | $ | — | $ | 189 | $ | 23 | $ | (1,243 | ) | |||||||||
__________________________________________________________________
(1) | Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle. |
110
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
10. Tangible Equity Units
In June 2015, the Company issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU is comprised of a prepaid equity purchase contract for common units of WGP and a senior amortizing note. Subsequent to issuance, each TEU may be legally separated into the two components. The prepaid equity purchase contract is considered a freestanding financial instrument, indexed to WGP common units, and meets the conditions for equity classification.
Anadarko allocated the proceeds from the issuance of the TEUs to equity and debt based on the relative fair values of their respective components as follows:
millions, except price per TEU | Equity Component | Debt Component | Total | ||||||||
Price per TEU | $ | 39.05 | $ | 10.95 | $ | 50.00 | |||||
Gross proceeds | 359 | 101 | 460 | ||||||||
Less issuance costs | 11 | 4 | 15 | ||||||||
Net proceeds | $ | 348 | $ | 97 | $ | 445 | |||||
The prepaid equity purchase contracts were recorded in noncontrolling interests, net of issuance costs, and the senior amortizing notes were recorded in short-term debt and long-term debt on the Company’s Consolidated Balance Sheet.
Equity Component Unless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018. Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC shares) in lieu of delivering WGP common units at settlement. The Company will deliver WGP common units (or APC shares) on the settlement date at the settlement rate based upon the applicable market value of WGP common units (or APC shares) as follows:
Settlement Rate per Purchase Contract | ||||
Applicable Market Value of WGP Common Units (1) | WGP Common Units | APC Shares (if elected) (1) | ||
Exceeds $69.8422 (Threshold Appreciation Price) | 0.7159 units (Minimum Settlement Rate) | a number of shares equal to (a) the Minimum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC shares | ||
Less than or equal to the Threshold Appreciation Price, but greater than or equal to $58.20 (Reference Price) | a number of units equal to $50.00, divided by the applicable market value of WGP common units | a number of shares equal to $50.00, divided by 98% of the applicable market value of APC shares | ||
Less than the Reference Price | 0.8591 units (Maximum Settlement Rate) | a number of shares equal to (a) the Maximum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC shares | ||
__________________________________________________________________
(1) | The applicable market value is the average of the daily volume-weighted average prices of WGP common units (or APC shares) for the 20 consecutive trading days beginning on, and including, the 23rd scheduled trading day immediately preceding June 7, 2018. |
111
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
10. Tangible Equity Units (Continued)
The WGP common units underlying the purchase contract are currently issued and outstanding, and are owned by a wholly owned subsidiary of Anadarko. In the event Anadarko elects to settle in APC shares, the number of such shares issued and delivered upon settlement of each purchase contract is subject to adjustment and cannot exceed four shares under any circumstance (APC share cap). The above fixed settlement rates for WGP common units and the APC share cap are subject to adjustment upon the occurrence of certain specified dilutive events such as certain increases in the WGP distribution rate.
Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. Beginning September 7, 2015, Anadarko will pay equal quarterly cash installments of $0.9375 per amortizing note (except for the September 7, 2015 installment payment, which was $0.9063 per amortizing note). The payments constitute a payment of interest and partial repayment of principal, with the aggregate per-year payments of principal and interest equating to a 7.50% cash payment with respect to each TEU. The senior amortizing notes have a final installment payment date of June 7, 2018, and are senior unsecured obligations of the Company.
112
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
11. Debt and Interest Expense
Debt The Company’s outstanding debt, excluding the capital lease obligation, is senior unsecured. See Note 8—Equity-Method Investments for disclosure regarding Anadarko’s notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense. The following summarizes the Company’s outstanding debt:
December 31, | |||||||
millions | 2015 | 2014 | |||||
Commercial paper | $ | 250 | $ | — | |||
5.950% Senior Notes due 2016 | 1,750 | 1,750 | |||||
6.375% Senior Notes due 2017 | 2,000 | 2,000 | |||||
7.050% Debentures due 2018 | 114 | 114 | |||||
Tangible equity units - senior amortizing notes due 2018 | 85 | — | |||||
WES 2.600% Senior Notes due 2018 | 350 | 350 | |||||
6.950% Senior Notes due 2019 | 300 | 300 | |||||
8.700% Senior Notes due 2019 | 600 | 600 | |||||
WES 5.375% Senior Notes due 2021 | 500 | 500 | |||||
WES 4.000% Senior Notes due 2022 | 670 | 670 | |||||
3.450% Senior Notes due 2024 | 625 | 625 | |||||
6.950% Senior Notes due 2024 | 650 | 650 | |||||
WES 3.950% Senior Notes due 2025 | 500 | — | |||||
7.500% Debentures due 2026 | 112 | 112 | |||||
7.000% Debentures due 2027 | 54 | 54 | |||||
7.125% Debentures due 2027 | 150 | 150 | |||||
6.625% Debentures due 2028 | 17 | 17 | |||||
7.150% Debentures due 2028 | 235 | 235 | |||||
7.200% Debentures due 2029 | 135 | 135 | |||||
7.950% Debentures due 2029 | 117 | 117 | |||||
7.500% Senior Notes due 2031 | 900 | 900 | |||||
7.875% Senior Notes due 2031 | 500 | 500 | |||||
Zero-Coupon Senior Notes due 2036 | 2,360 | 2,360 | |||||
6.450% Senior Notes due 2036 | 1,750 | 1,750 | |||||
7.950% Senior Notes due 2039 | 325 | 325 | |||||
6.200% Senior Notes due 2040 | 750 | 750 | |||||
4.500% Senior Notes due 2044 | 625 | 625 | |||||
WES 5.450% Senior Notes due 2044 | 400 | 400 | |||||
7.730% Debentures due 2096 | 61 | 61 | |||||
7.500% Debentures due 2096 | 78 | 78 | |||||
7.250% Debentures due 2096 | 49 | 49 | |||||
WES revolving credit facility | 300 | 510 | |||||
Total borrowings at face value | $ | 17,312 | $ | 16,687 | |||
Net unamortized discounts and premiums (1) | (1,581 | ) | (1,616 | ) | |||
Total borrowings | $ | 15,731 | $ | 15,071 | |||
Capital lease obligation | 20 | 21 | |||||
Less current portion of long-term debt | 33 | — | |||||
Total long-term debt (2) | $ | 15,718 | $ | 15,092 | |||
__________________________________________________________________
(1) | Unamortized discounts and premiums are amortized over the term of the related debt. |
(2) | The total long-term debt balance for WES was $2.7 billion at December 31, 2015, and $2.4 billion at December 31, 2014. |
113
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
11. Debt and Interest Expense (Continued)
In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing the Zero-Coupon Senior Notes due 2036 (Zero Coupons). The Zero Coupons mature in 2036 and have an aggregate principal amount due at maturity of approximately $2.4 billion, reflecting a yield to maturity of 5.24%. The Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. The accreted value of the outstanding Zero Coupons was $806 million at December 31, 2015. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at December 31, 2015, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.
Anadarko’s $1.750 billion 5.950% Senior Notes due September 2016 were classified as long-term debt on the Company’s Consolidated Balance Sheet at December 31, 2015, as Anadarko intends to refinance these obligations prior to or at maturity with new long-term debt issuances or by using the $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility).
Fair Value The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $15.7 billion at December 31, 2015, and $17.4 billion at December 31, 2014.
Debt Activity The following summarizes the Company’s debt activity:
millions | Carrying Value | Description | |||
Balance at December 31, 2013 | $ | 13,557 | |||
Issuances | 101 | WES 2.600% Senior Notes due 2018 | |||
394 | WES 5.450% Senior Notes due 2044 | ||||
624 | 3.450% Senior Notes due 2024 | ||||
621 | 4.500% Senior Notes due 2044 | ||||
Borrowings | 1,160 | WES revolving credit facility | |||
Repayments | (500 | ) | 7.625% Senior Notes due 2014 | ||
(275 | ) | 5.750% Senior Notes due 2014 | |||
(650 | ) | WES revolving credit facility | |||
Other, net | 39 | Amortization of debt discounts and premiums | |||
Balance at December 31, 2014 | $ | 15,071 | |||
Issuances | 494 | WES 3.950% Senior Notes due 2025 | |||
101 | Tangible equity units - senior amortizing notes | ||||
Borrowings | 1,500 | $5.0 billion revolving credit facility | |||
1,800 | 364-Day Facility | ||||
400 | WES revolving credit facility | ||||
250 | Commercial paper notes, net (1) | ||||
Repayments | (1,500 | ) | $5.0 billion revolving credit facility | ||
(1,800 | ) | 364-Day Facility | |||
(610 | ) | WES revolving credit facility | |||
(16 | ) | Tangible equity units - senior amortizing notes | |||
Other, net | 41 | Amortization of debt discounts and premiums | |||
Balance at December 31, 2015 | $ | 15,731 | |||
__________________________________________________________________
(1) | Includes repayments of $(106) million related to commercial paper notes with maturities greater than 90 days. |
114
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
11. Debt and Interest Expense (Continued)
Anadarko Revolving Credit Facilities and Commercial Paper Program In June 2014, Anadarko entered into the Five-Year Facility and a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility). In January 2015, upon satisfaction of certain conditions, including the payment of the settlement related to the Tronox Adversary Proceeding, these facilities replaced the $5.0 billion Facility. In December 2015, the Company amended the Five-Year Facility to extend the maturity date to January 2021 and in January 2016, the Company replaced the 364-Day Facility with a new $2.0 billion 364-day senior unsecured revolving facility on identical terms that will mature in 2017.
Borrowings under the Five-Year Facility and the 364-Day Facility (collectivity, the Credit Facilities) generally bear interest under one of two rate options, at Anadarko’s election, using either LIBOR (or Euro Interbank Offered Rate in the case of borrowings under the Five-Year Facility denominated in Euro) or an alternate base rate, in each case plus an applicable margin ranging from 0.00% to 1.65% for the Five-Year Facility and 0.00% to 1.675% for the 364-Day Facility. The applicable margin will vary depending on Anadarko’s credit ratings.
The Credit Facilities contain certain customary affirmative and negative 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. At December 31, 2015, the Company had no outstanding borrowings under the Credit Facilities and was in compliance with all covenants contained therein.
In January 2015, the Company initiated a commercial paper program, which allows a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Five-Year Facility. The maturities of the commercial paper notes vary, but may not exceed 397 days. The commercial paper notes are sold under customary terms in the commercial paper market and are issued either at a discounted price to their principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted price or interest amounts are dependent on market conditions and the ratings assigned to the commercial paper program by credit rating agencies at the time of issuance of the commercial paper notes. At December 31, 2015, the Company had $250 million of commercial paper notes outstanding at a weighted-average interest rate of 0.98%. Anadarko classified the outstanding commercial paper notes as long-term debt on the Company’s Consolidated Balance Sheet at December 31, 2015, as the Company currently intends to refinance these obligations at maturity with additional commercial paper notes supported by the Five-Year Facility.
WES Borrowings In February 2014, WES amended and restated its then-existing $800 million senior unsecured revolving credit facility by entering into a five-year, $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which is expandable to a maximum of $1.5 billion. Borrowings under the RCF bear interest at LIBOR plus an applicable margin ranging from 0.975% to 1.45% depending on WES’s credit rating, or the greatest of (i) rates at a margin above the one-month LIBOR, (ii) the federal funds rate, or (iii) prime rates offered by certain designated banks. At December 31, 2015, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $300 million at an interest rate of 1.73%, and had available borrowing capacity of approximately $894 million ($1.2 billion capacity, less $300 million of outstanding borrowings and $6 million of outstanding letters of credit).
115
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
11. Debt and Interest Expense (Continued)
Scheduled Maturities Total principal amount of debt maturities for the five years ending December 31, 2020, excluding the potential repayment of the outstanding Zero Coupons that may be put by the holders to the Company annually, were as follows:
millions | Principal Amount of Debt Maturities | ||
2016 | $ | 2,033 | |
2017 | 2,034 | ||
2018 | 482 | ||
2019 | 1,200 | ||
2020 | — | ||
Interest Expense The following summarizes interest expense for the years ended December 31:
millions | 2015 | 2014 | 2013 | ||||||||
Debt and other | $ | 989 | $ | 973 | $ | 949 | |||||
Capitalized interest | (164 | ) | (201 | ) | (263 | ) | |||||
Total interest expense | $ | 825 | $ | 772 | $ | 686 | |||||
12. Income Taxes
The following summarizes components of income tax expense (benefit) for the years ended December 31:
millions | 2015 | 2014 | 2013 | ||||||||
Current | |||||||||||
Federal | $ | (177 | ) | $ | 188 | $ | 113 | ||||
State | (18 | ) | 2 | 42 | |||||||
Foreign | 495 | 1,574 | 873 | ||||||||
300 | 1,764 | 1,028 | |||||||||
Deferred | |||||||||||
Federal | (2,929 | ) | (389 | ) | 94 | ||||||
State | (145 | ) | 27 | (9 | ) | ||||||
Foreign | (103 | ) | 215 | 52 | |||||||
(3,177 | ) | (147 | ) | 137 | |||||||
Total income tax expense (benefit) | $ | (2,877 | ) | $ | 1,617 | $ | 1,165 | ||||
116
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
12. Income Taxes (Continued)
Total income taxes differed from the amounts computed by applying the U.S. federal statutory income tax rate to income (loss) before income taxes. The following summarizes the sources of these differences for the years ended December 31:
millions except percentages | 2015 | 2014 | 2013 | ||||||||
Income (loss) before income taxes | |||||||||||
Domestic | $ | (9,155 | ) | $ | (3,564 | ) | $ | 428 | |||
Foreign | (534 | ) | 3,618 | 1,678 | |||||||
Total | $ | (9,689 | ) | $ | 54 | $ | 2,106 | ||||
U.S. federal statutory tax rate | 35 | % | 35 | % | 35 | % | |||||
Tax computed at the U.S. federal statutory rate | $ | (3,391 | ) | $ | 19 | $ | 737 | ||||
Adjustments resulting from | |||||||||||
State income taxes (net of federal income tax benefit) | (81 | ) | (11 | ) | 23 | ||||||
Tax impact from foreign operations | 299 | 62 | 204 | ||||||||
Non-deductible Algerian exceptional profits tax | 102 | 193 | 144 | ||||||||
Net changes in uncertain tax positions | 54 | 1,427 | (29 | ) | |||||||
Deferred tax adjustments | 10 | 15 | 76 | ||||||||
Non-deductible Tronox-related contingent loss | — | (36 | ) | 36 | |||||||
(Income) loss attributable to noncontrolling interests | 42 | (66 | ) | (48 | ) | ||||||
Non-deductible Deepwater Horizon costs | 26 | 32 | — | ||||||||
Federal manufacturing deduction | — | (27 | ) | — | |||||||
Dispositions of non-deductible goodwill | 62 | 21 | — | ||||||||
Other, net | — | (12 | ) | 22 | |||||||
Total income tax expense (benefit) | $ | (2,877 | ) | $ | 1,617 | $ | 1,165 | ||||
Effective tax rate | 30 | % | 2,994 | % | 55 | % | |||||
The following summarizes components of total deferred taxes at December 31:
millions | 2015 | 2014 | |||||
Federal | $ | (4,721 | ) | $ | (7,649 | ) | |
State, net of federal | (248 | ) | (341 | ) | |||
Foreign | (431 | ) | (537 | ) | |||
Total deferred taxes | $ | (5,400 | ) | $ | (8,527 | ) | |
117
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
12. Income Taxes (Continued)
The following summarizes tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31:
millions | 2015 | 2014 | |||||
Deferred tax liabilities | |||||||
Oil and gas exploration and development operations | $ | (5,643 | ) | $ | (8,418 | ) | |
Midstream and other depreciable properties | (1,049 | ) | (1,611 | ) | |||
Mineral operations | (492 | ) | (412 | ) | |||
Other | (470 | ) | (351 | ) | |||
Gross long-term deferred tax liabilities | (7,654 | ) | (10,792 | ) | |||
Deferred tax assets | |||||||
Foreign and state net operating loss carryforwards | 586 | 558 | |||||
U.S. foreign tax credit carryforwards | 1,254 | 166 | |||||
Compensation and benefit plans | 615 | 701 | |||||
Mark to market on derivatives | 441 | 354 | |||||
Settlement agreement related to the Tronox Adversary Proceeding | — | 590 | |||||
Other | 761 | 760 | |||||
Gross long-term deferred tax assets | 3,657 | 3,129 | |||||
Valuation allowances on deferred tax assets not expected to be realized | (1,403 | ) | (864 | ) | |||
Net long-term deferred tax assets | 2,254 | 2,265 | |||||
Total deferred taxes | $ | (5,400 | ) | $ | (8,527 | ) | |
The valuation allowance primarily relates to U.S. foreign tax credit carryforwards and foreign and state net operating loss carryforwards, which reduces the Company’s net deferred tax asset to an amount that will more likely than not be realized within the carryforward period.
The following summarizes changes in the balance of valuation allowances on deferred tax assets:
millions | 2015 | 2014 | 2013 | ||||||||
Balance at January 1 | $ | (864 | ) | $ | (818 | ) | $ | (922 | ) | ||
Changes due to U.S. foreign tax credits | (384 | ) | 11 | 58 | |||||||
Changes due to foreign and state net operating loss carryforwards | 10 | 64 | (57 | ) | |||||||
Changes due to foreign capitalized costs | (165 | ) | (121 | ) | 103 | ||||||
Balance at December 31 | $ | (1,403 | ) | $ | (864 | ) | $ | (818 | ) | ||
Tax carryforwards available for use on future income tax returns, prior to valuation allowance, at December 31, 2015, were as follows:
millions | Domestic | Foreign | Expiration | ||||||
Net operating loss—foreign | $ | — | $ | 1,264 | 2016 - Indefinite | ||||
Net operating loss—state | $ | 4,762 | $ | — | 2016-2035 | ||||
Foreign tax credits | $ | 1,254 | $ | — | 2023-2026 | ||||
Texas margins tax credit | $ | 33 | $ | — | 2026 | ||||
118
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
12. Income Taxes (Continued)
The following summarizes taxes receivable (payable) related to income tax expense (benefit) at December 31:
millions | ||||||||
Balance Sheet Classification | 2015 | 2014 | ||||||
Income taxes receivable | ||||||||
Accounts receivable—other | $ | 1,046 | $ | 93 | ||||
Other assets | 61 | 35 | ||||||
1,107 | 128 | |||||||
Income taxes (payable) | ||||||||
Accrued expense | (9 | ) | (152 | ) | ||||
Total net income taxes receivable (payable) | $ | 1,098 | $ | (24 | ) | |||
Changes in the balance of unrecognized tax benefits excluding interest and penalties on uncertain tax positions were as follows:
Assets (Liabilities) | |||||||||||
millions | 2015 | 2014 | 2013 | ||||||||
Balance at January 1 | $ | (1,687 | ) | $ | (147 | ) | $ | (46 | ) | ||
Increases related to prior-year tax positions | (99 | ) | (11 | ) | (54 | ) | |||||
Decreases related to prior-year tax positions | 89 | 39 | 3 | ||||||||
Increases related to current-year tax positions | (263 | ) | (1,568 | ) | (72 | ) | |||||
Settlements | 180 | — | 5 | ||||||||
Lapse of statute of limitations | — | — | 17 | ||||||||
Balance at December 31 | $ | (1,780 | ) | $ | (1,687 | ) | $ | (147 | ) | ||
Included in the 2015 ending balance of unrecognized tax benefits presented above are potential benefits of $1.756 billion, of which, if recognized, $1.337 billion would affect the effective tax rate on income, and $395 million would be in the form of foreign tax credits and net operating loss carryforwards that would be offset with a full valuation allowance. Also included in the 2015 ending balance are benefits of $24 million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain.
As of December 31, 2015, the Company had recorded a total tax benefit of $576 million related to the Tronox-related contingent liability. This benefit is net of a $1.3 billion uncertain tax position due to the uncertainty related to the deductibility of the settlement payment. The Company is a participant in the U.S. Internal Revenue Service’s (IRS) Compliance Assurance Process for the 2015 tax year and has regular discussions with the IRS concerning the Company’s tax position. Depending on the outcome of such discussions, it is reasonably possible that the amount of the uncertain tax position related to the settlement could change, perhaps materially. See Note 15—Contingencies—Tronox Litigation.
Income tax audits and the Company’s acquisition and divestiture activity have given rise to tax disputes in U.S. and foreign jurisdictions. See Note 15—Contingencies—Other Litigation. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by $400 million to $410 million due to settlements with taxing authorities or lapse in statutes of limitation. The majority of the possible decrease relates to foreign tax credit amounts that would be offset with a full valuation allowance and would have no effect on the effective tax rate. With the exception of the deductibility of the Tronox settlement payment discussed above, management does not believe that the final resolution of outstanding tax audits and litigation will have a material adverse effect on the Company’s consolidated financial condition, results of operations, or cash flows.
119
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
12. Income Taxes (Continued)
The Company had accrued approximately $11 million of interest related to uncertain tax positions at December 31, 2015, and $9 million at December 31, 2014. The Company recognized interest and penalties in income tax expense (benefit) of $2 million during 2015 and $1 million during 2014.
Anadarko is subject to audit by tax authorities in the U.S. federal, state, and local tax jurisdictions as well as in various foreign jurisdictions. The following lists the tax years subject to examination by major tax jurisdiction:
Tax Years | |
United States | 2008-2015 |
Algeria | 2012-2015 |
Ghana | 2006-2015 |
13. Asset Retirement Obligations
The majority of Anadarko’s AROs relate to the plugging of wells and the related abandonment of oil and gas properties. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement. The following summarizes changes in the Company’s AROs:
millions | 2015 | 2014 | |||||
Carrying amount of asset retirement obligations at January 1 | $ | 2,053 | $ | 2,022 | |||
Liabilities incurred | 104 | 119 | |||||
Property dispositions | (108 | ) | (70 | ) | |||
Liabilities settled | (298 | ) | (443 | ) | |||
Accretion expense | 102 | 93 | |||||
Revisions in estimated liabilities | 206 | 332 | |||||
Carrying amount of asset retirement obligations at December 31 | $ | 2,059 | $ | 2,053 | |||
120
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
14. Commitments
Operating Leases At December 31, 2015, the Company had $1.8 billion in long-term drilling rig commitments that satisfy operating lease criteria. The Company also had $329 million of various commitments under non-cancelable operating lease agreements for production platforms and equipment, buildings, facilities, compressors, and aircraft. These operating leases expire at various dates through 2026. Certain of these operating leases contain residual value guarantees at the end of the lease term, totaling $81 million at December 31, 2015. No liability has been accrued for residual value guarantees. In addition, these operating leases include options to purchase the leased property during or at the end of the lease term for the fair market value or other specified amount at that time. The following summarizes future minimum lease payments under operating leases at December 31, 2015:
millions | |||
2016 | $ | 806 | |
2017 | 604 | ||
2018 | 352 | ||
2019 | 228 | ||
2020 | 86 | ||
Later years | 41 | ||
Total future minimum lease payments | $ | 2,117 | |
Anadarko has entered into various agreements to secure drilling rigs necessary to support the execution of its drilling plans over the next several years. The table of future minimum lease payments above includes $1.7 billion related to five offshore drilling vessels and $98 million related to certain contracts for U.S. onshore drilling rigs. Lease payments associated with the drilling of exploratory wells and development wells net of amounts billed to partners will initially be capitalized as a component of oil and gas properties, and either depreciated or impaired in future periods or written off as exploration expense.
Total rent expense, net of sublease income and amounts capitalized, amounted to $77 million in 2015, $85 million in 2014, and $119 million in 2013. Total rent expense includes contingent rent expense related to transportation and processing fees of $17 million in 2015, $22 million in 2014, and $24 million in 2013.
Other Commitments In the normal course of business, the Company enters into other contractual agreements for processing, treating, transportation, and storage of oil, natural gas, and NGLs as well as for other oil and gas activities. These agreements expire at various dates through 2036. At December 31, 2015, aggregate future payments under these contracts totaled $10.1 billion, of which $1.9 billion is expected to be paid in 2016, $1.7 billion in 2017, $1.3 billion in 2018, $1.2 billion in 2019, $1.1 billion in 2020, and $2.9 billion thereafter.
121
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
15. Contingencies
Litigation The Company is a defendant in a number of lawsuits, is involved in governmental proceedings, and is subject to regulatory controls arising in the ordinary course of business, including personal injury claims; property damage claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas exploration, 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. The Company’s Consolidated Balance Sheets include liabilities of $269 million at December 31, 2015, and $5.3 billion at December 31, 2014, for litigation-related contingencies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial condition, results of operations, or cash flows.
Deepwater Horizon Events In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig, resulting in an oil spill. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated interest. In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement), under which the Company paid $4.0 billion in cash and transferred its interest in the Macondo well and the Mississippi Canyon Block 252 (Lease) to BP. Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and any claims arising under the Operating Agreement with BP (OA). This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against penalties and fines, punitive damages, shareholder derivative or securities laws claims, or certain other claims.
Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company by, among others, fishing, boating, and shrimping enterprises and industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the States of Alabama, Louisiana, Texas, and Mississippi, and several of their political subdivisions; the U.S. Department of Justice (DOJ); environmental non-governmental organizations; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence, and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the Clean Water Act (CWA); and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs seek actual damages, punitive damages, declaratory judgment, and/or injunctive relief. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (Louisiana District Court).
In July 2015, BP announced a settlement agreement in principle with the DOJ 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. A hearing related to the consent decree is currently scheduled for March 2016.
122
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
15. Contingencies (Continued)
Liability Accrual Below is a discussion of the Company’s current analysis, under applicable accounting guidance, of its potential liability for (i) amounts under the OA (OA Liabilities), (ii) OPA-related environmental costs, and (iii) other contingent liabilities. Applicable accounting guidance requires the Company to accrue a liability if both (a) it is probable that a liability has been incurred and (b) the amount of that liability can be reasonably estimated.
The Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and other potential liabilities. The Company may be required to recognize a liability for these amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c. The Company has not recorded a liability for any costs that are subject to indemnification by BP.
OA Liabilities Pursuant to the Settlement Agreement, all amounts deemed by BP to have been due under the OA, as well as all future amounts that otherwise would be invoiced to Anadarko under the OA, have been satisfied.
OPA-Related Environmental Costs BP, Anadarko, and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the U.S. Coast Guard (USCG) referencing their identification as a “responsible party or guarantor” (RP) under OPA. Under OPA, RPs, including Anadarko, may be jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons as well as other costs and damage claims related to the spill and spill cleanup. The USCG’s identification of Anadarko as an RP arises as a result of Anadarko’s status as a co-lessee in the Lease.
Under accounting guidance applicable to environmental liabilities, a liability is presumed probable if the entity is both identified as an RP and associated with the environmental event. The Company’s co-lessee status in the Lease at the time of the event and the subsequent identification and treatment of the Company as an RP satisfies these standards and therefore establishes the presumption that the Company’s potential environmental liabilities related to the Deepwater Horizon events are probable.
As BP funds OPA-related environmental costs, any potential joint and several liability for these costs is satisfied for all RPs, including Anadarko. This bears significance in that once these costs are funded by BP, such costs are no longer analyzed as OPA-related environmental costs, but instead are analyzed as OA Liabilities. As discussed above, Anadarko has settled its OA Liabilities with BP. Thus, potential liability to the Company for OPA-related environmental costs can arise only where BP does not, or otherwise is unable to, fund all of the OPA-related environmental costs. Under this scenario, the joint and several nature of the liability for these costs could cause the Company to recognize a liability for OPA-related environmental costs. However, all liability relating to OPA-related environmental costs should be resolved as part of the BP Settlement, provided that the consent decree is ultimately approved by the Louisiana District Court. Additionally, in the event the consent decree is not approved by the Louisiana District Court, the Company is fully indemnified by BP against these costs (including guarantees by BPCNA or BP p.l.c.).
Allocable Share of Gross OPA-Related Environmental Costs Under applicable accounting guidance, the Company is required to estimate its allocable share of gross OPA-related environmental costs. To date, BP has paid all Deepwater Horizon event-related costs, which satisfies the Company’s potential liability for these costs. Additionally, BP has entered into the BP Settlement Agreement to resolve all liability associated with these costs. Based on the BP Settlement Agreement, BP’s stated intent to continue funding these costs, the Company’s assessment of BP’s financial ability to continue funding these costs, and the impact of BP’s settlements with both of its OA partners, the Company believes the likelihood of BP not continuing to satisfy these claims to be remote. Accordingly, the Company considers zero to be its allocable share of gross OPA-related environmental costs and, consistent with applicable accounting guidance, has not recorded a liability for these amounts.
123
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
15. Contingencies (Continued)
Penalties and Fines These costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state, and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, the CWA, the Outer Continental Shelf Lands Act, the Migratory Bird Treaty Act, and possibly other federal, state, and local laws. The foregoing does not represent an exhaustive list of statutes and regulations that potentially could trigger a penalty or fine assessment against the Company. In December 2010, the DOJ 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 Louisiana District Court. In an effort to resolve this matter, the Company made a settlement offer to the DOJ in July 2014 and had a contingent liability of $90 million recorded as of December 31, 2014. 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 Section 311 of the CWA as a working-interest owner in the Macondo well and entered a judgment of $159.5 million in December 2015. The Company recorded an additional contingent liability during 2015 for $69.5 million, for a total liability of $159.5 million at December 31, 2015. The deadline for an appeal of the decision was February 16, 2016. The parties did not appeal the decision; accordingly, the Company expects to pay the penalty in the first quarter of 2016.
As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments appealed, or provided indication of a likely appeal of, the Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. These appeals should be dismissed as part of the BP Settlement, provided that the consent decree is ultimately approved by the Louisiana District Court. In the event the consent decree is not approved by the Louisiana District Court and any such appeal proceeds and is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.
Natural Resource Damages This category includes future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of injury assessments and restoration planning. Natural resources generally include land, fish, water, air, wildlife, and other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state, or local government. The NRD assessment process is led by various federal agencies and affected states. Referred to as the “Co-Trustees,” these entities continue to conduct injury assessment and restoration planning. NRD claims are generally sought after the damage assessment and restoration planning is completed, which may take several years. Thus, the Company remains unable to reasonably estimate the magnitude of any NRD claim. However, all NRD claims should be dismissed as part of the BP Settlement, provided that the consent decree is ultimately approved by the Louisiana District Court. In the event the Louisiana District Court does not approve the consent decree, the Company anticipates that BP will satisfy any NRD claim, which eliminates any potential liability to Anadarko for such costs. In the event any NRD damage claim is made directly against Anadarko, the Company is fully indemnified by BP against such claims (including guarantees by BPCNA or BP p.l.c.).
124
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
15. Contingencies (Continued)
Civil Litigation Damage Claims As discussed above, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment, and/or injunctive relief. However, all claims relating to this MDL action should be dismissed as part of the BP Settlement, provided that the consent decree is ultimately approved by the Louisiana District Court. Additionally, in the event the consent decree is not approved by the Louisiana District Court, the Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.
Remaining Liability Outlook It is possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential penalties and fines and certain royalty claims not covered by the indemnification provisions of the Settlement Agreement.
Tronox Litigation On November 28, 2005, Tronox Incorporated (Tronox), at the time a subsidiary of Kerr-McGee Corporation, completed an initial public offering (IPO) and was subsequently spun-off from Kerr-McGee Corporation. In August 2006, Anadarko acquired all of the stock of Kerr-McGee Corporation. In January 2009, Tronox and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York (Bankruptcy Court), which is the court that presided over the Adversary Proceeding (defined below). In May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) asserting several claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleged, among other things, that it was insolvent or undercapitalized at the date of its IPO and sought, among other things, to recover damages in excess of $18.85 billion from Kerr-McGee and Anadarko as well as interest and attorneys’ fees and costs. In accordance with Tronox’s Bankruptcy Court-approved Plan of Reorganization (Plan), the Adversary Proceeding was pursued by a litigation trust (Litigation Trust). Pursuant to the Plan, the Litigation Trust was “deemed substituted” for the Tronox plaintiffs in the Adversary Proceeding. For purposes of this Form 10-K, references to “Tronox” after February 2011 refer to the Litigation Trust.
The U.S. government intervened in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). The Litigation Trust and the U.S. government agreed that the recovery of damages under the Adversary Proceeding, if any, would cover both the Adversary Proceeding and the FDCPA Complaint.
125
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
15. Contingencies (Continued)
Liability Accrual On April 3, 2014, Anadarko and Kerr-McGee entered into a settlement agreement with the Litigation Trust and the U.S. government (in its capacity as plaintiff-intervenor and acting for and on behalf of certain U.S. government agencies) to resolve all claims asserted in the Adversary Proceeding and FDCPA Complaint for $5.15 billion, which represents principal of approximately $3.98 billion plus 6% interest from the filing of the Adversary Proceeding on May 12, 2009, through April 3, 2014. In addition, the Company agreed to pay interest on the above amount from April 3, 2014, through the payment of the settlement, with an annual interest rate of 1.5% for the first 180 days and 1.5% plus the one-month LIBOR thereafter. Under the terms of the settlement agreement, the Litigation Trust, Anadarko, and Kerr-McGee agreed to mutually release all claims that were or could have been asserted in the Adversary Proceeding. The U.S. government (representing federal agencies that filed claims in the Tronox bankruptcy), Anadarko, and Kerr-McGee also provided covenants not to sue each other with respect to certain claims and causes of action. The U.S. government also provided contribution protection from third-party claims seeking reimbursement from Anadarko and certain of its affiliates for the sites identified in the settlement agreement. In January 2015, the Company paid $5.2 billion after the settlement agreement became effective.
Anadarko recognized Tronox-related contingent losses of $850 million in the fourth quarter of 2013 and $4.3 billion in the first quarter of 2014. In addition, Anadarko recognized settlement-related interest expense, included in Tronox-related contingent loss in the Company’s Consolidated Statements of Income, of $60 million during 2014 and $5 million during the first quarter of 2015. At December 31, 2015, there was no Tronox-related contingent liability on the Company’s Consolidated Balance Sheet. For information on the tax effects of the Tronox settlement agreement, see Note 12—Income Taxes.
Other Litigation In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. In December 2008, the Company deposited the amount of tax originally in dispute in a Brazilian real-denominated judicially-controlled Brazilian bank account pending final resolution of the matter. At December 31, 2015, the deposit of $86 million is included in other assets on the Company’s Consolidated Balance Sheet.
In July 2009, the lower judicial court ruled in favor of the Brazilian tax authorities. The Company appealed this decision to the Brazilian Regional courts, which upheld the lower court’s ruling in favor of the Brazilian tax authorities in December 2011. In April 2012, the Company filed simultaneous appeals to the Brazilian Superior Court and the Brazilian Supreme Court. The Brazilian Superior Court and the Brazilian Supreme Court have agreed to hear the case and the Company currently is awaiting the setting of initial hearing dates.
In August 2013, following a determination by an administrative court in a related matter that the amount of tax in dispute was not calculated properly, the Company filed a petition requesting the withdrawal of a portion of the judicial deposit to the extent it exceeds the amount of tax currently in dispute and any interest on such excess amount. In April 2015, the Company’s petition was denied. The Company appealed this decision. The appeal was denied in November 2015.
The Company believes that it will more likely than not prevail in the Brazilian Superior Court and the Brazilian Supreme Court. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation at December 31, 2015. The Company continues to vigorously defend its position in Brazilian courts.
126
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
15. Contingencies (Continued)
Guarantees and Indemnifications The Company provides certain indemnifications in relation to asset dispositions. These indemnifications typically relate to disputes, litigation, or tax matters existing at the date of disposition. In 2013, as a result of a Chapter 11 bankruptcy declaration by a third party, the Department of the Interior ordered Anadarko to perform the decommissioning of a production facility and related wells, which were previously sold to the third party. During 2013, the Company accrued costs of $117 million to decommission the production facility and related wells, reported in other (income) expense, net in the Company’s Consolidated Statement of Income. During each of the years ended December 31, 2015 and 2014, the Company recognized a $22 million increase in the estimated decommissioning costs. Anadarko completed decommissioning of the production facility in 2014 and expects to complete decommissioning of the wells in 2016. Decommissioning obligations of $116 million at December 31, 2015, and $114 million at December 31, 2014, were included in accrued expenses on the Company’s Consolidated Balance Sheets. Actual costs may vary from this estimate; however, the Company does not believe that any such change will materially impact its financial condition, results of operations, or cash flows.
Environmental Matters Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. The Company’s Consolidated Balance Sheets include liabilities for remediation and reclamation obligations of $145 million at December 31, 2015, and $126 million at December 31, 2014. The current portion of these amounts was included in accounts payable and the long-term portion of these amounts was included in other long-term liabilities—other on the Company’s Consolidated Balance Sheets. The Company continually monitors remediation and reclamation processes and adjusts its liability for these obligations as necessary.
The Company is one of numerous parties previously notified by the California Department of Toxic Substances Control (DTSC) that, as a result of a prior acquisition, it is a potentially responsible party with respect to a landfill located in West Covina, California. While no agreement is in place with the DTSC, the Company recorded a $50 million restoration liability in 2013 with respect to the site, representing the current estimated obligation, which is included in the Company’s liability balance at December 31, 2015. The Company could incur additional obligations if any of the potentially responsible parties are ultimately not able to fund their allocated share of the costs or if the DTSC requires a more costly remedial approach. It is possible that the Company’s current estimate of probable loss related to this matter could change, perhaps materially, in the future.
127
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
16. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans
The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is non-contributory.
The following sets forth changes in the benefit obligations and fair value of plan assets for the Company’s pension and other postretirement benefit plans for the years ended December 31, 2015 and 2014, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2015 and 2014:
Pension Benefits | Other Benefits | ||||||||||||||
millions | 2015 | 2014 | 2015 | 2014 | |||||||||||
Change in benefit obligation | |||||||||||||||
Benefit obligation at beginning of year | $ | 2,528 | $ | 2,158 | $ | 373 | $ | 294 | |||||||
Service cost | 118 | 99 | 9 | 7 | |||||||||||
Interest cost | 101 | 99 | 15 | 15 | |||||||||||
Plan amendments | — | — | (89 | ) | — | ||||||||||
Actuarial (gain) loss | (115 | ) | 337 | (27 | ) | 72 | |||||||||
Participant contributions | — | 1 | 5 | 4 | |||||||||||
Benefit payments | (194 | ) | (159 | ) | (20 | ) | (19 | ) | |||||||
Foreign-currency exchange-rate changes | (7 | ) | (7 | ) | — | — | |||||||||
Benefit obligation at end of year (1) | $ | 2,431 | $ | 2,528 | $ | 266 | $ | 373 | |||||||
Change in plan assets | |||||||||||||||
Fair value of plan assets at beginning of year | $ | 1,818 | $ | 1,754 | $ | — | $ | — | |||||||
Actual return on plan assets | 16 | 111 | — | — | |||||||||||
Employer contributions | 43 | 121 | 15 | 15 | |||||||||||
Participant contributions | — | 1 | 5 | 4 | |||||||||||
Benefit payments | (194 | ) | (159 | ) | (20 | ) | (19 | ) | |||||||
Foreign-currency exchange-rate changes | (9 | ) | (10 | ) | — | — | |||||||||
Fair value of plan assets at end of year | $ | 1,674 | $ | 1,818 | $ | — | $ | — | |||||||
Funded status of the plans at end of year | $ | (757 | ) | $ | (710 | ) | $ | (266 | ) | $ | (373 | ) | |||
Total recognized amounts in the balance sheet consist of | |||||||||||||||
Other assets | $ | 41 | $ | 41 | $ | — | $ | — | |||||||
Accrued expenses | (24 | ) | (24 | ) | (16 | ) | (15 | ) | |||||||
Other long-term liabilities—other | (774 | ) | (727 | ) | (250 | ) | (358 | ) | |||||||
Total | $ | (757 | ) | $ | (710 | ) | $ | (266 | ) | $ | (373 | ) | |||
Total recognized amounts in accumulated other comprehensive income consist of | |||||||||||||||
Prior service cost (credit) | $ | (1 | ) | $ | (1 | ) | $ | (84 | ) | $ | 2 | ||||
Net actuarial (gain) loss | 655 | 740 | (25 | ) | 1 | ||||||||||
Total | $ | 654 | $ | 739 | $ | (109 | ) | $ | 3 | ||||||
__________________________________________________________________
(1) | The accumulated benefit obligation for all defined-benefit pension plans was $2.1 billion at both December 31, 2015 and December 31, 2014. |
128
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
16. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
The following summarizes the Company’s defined-benefit pension plans with accumulated benefit obligations in excess of plan assets for the years ended December 31:
millions | 2015 | 2014 | |||||
Projected benefit obligation | $ | 2,309 | $ | 2,403 | |||
Accumulated benefit obligation | 1,954 | 2,024 | |||||
Fair value of plan assets | 1,511 | 1,652 | |||||
The following summarizes the Company’s pension and other postretirement benefit cost and amounts recognized in other comprehensive income (before tax benefit) for the years ended December 31:
Pension Benefits | Other Benefits | ||||||||||||||||||||||
millions | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||
Components of net periodic benefit cost | |||||||||||||||||||||||
Service cost | $ | 118 | $ | 99 | $ | 85 | $ | 9 | $ | 7 | $ | 9 | |||||||||||
Interest cost | 101 | 99 | 78 | 15 | 15 | 14 | |||||||||||||||||
Expected return on plan assets | (109 | ) | (106 | ) | (91 | ) | — | — | — | ||||||||||||||
Amortization of net actuarial loss (gain) | 52 | 34 | 118 | — | (7 | ) | — | ||||||||||||||||
Amortization of net prior service cost (credit) | — | — | — | (4 | ) | — | 1 | ||||||||||||||||
Settlement loss | 11 | — | 14 | — | — | — | |||||||||||||||||
Net periodic benefit cost | $ | 173 | $ | 126 | $ | 204 | $ | 20 | $ | 15 | $ | 24 | |||||||||||
Amounts recognized in other comprehensive income (expense) | |||||||||||||||||||||||
Net actuarial gain (loss) | $ | 22 | $ | (333 | ) | $ | 342 | $ | 27 | $ | (72 | ) | $ | 74 | |||||||||
Amortization of net actuarial (gain) loss | 52 | 34 | 118 | — | (7 | ) | — | ||||||||||||||||
Net prior service (cost) credit | — | — | — | 89 | — | — | |||||||||||||||||
Amortization of net prior service cost (credit) | — | — | — | (4 | ) | — | 1 | ||||||||||||||||
Settlement loss | 11 | — | 14 | — | — | — | |||||||||||||||||
Total amounts recognized in other comprehensive income (expense) | $ | 85 | $ | (299 | ) | $ | 474 | $ | 112 | $ | (79 | ) | $ | 75 | |||||||||
The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan. In 2016, an estimated $34 million of net actuarial loss and $27 million of net prior service credit for the pension and other postretirement plans will be amortized from accumulated other comprehensive income into net periodic benefit cost.
129
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
16. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future compensation increases, and the health care cost trend rate or inflation (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually.
Accumulated and projected benefit obligations are measured as the present value of future cash payments. The Company discounts those cash payments using a discount rate that reflects the weighted average of market-observed yields for select high-quality (AA-rated) fixed-income securities with cash flows that correspond to the expected amounts and timing of benefit payments. The discount-rate assumption used by the Company represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date. Assumed rates of compensation increases for active participants vary by age group, with the resulting weighted-average assumed rate (weighted by the plan-level benefit obligation) provided in the preceding table.
The following summarizes the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations and net periodic benefit cost for the years ended December 31:
Pension Benefits | Other Benefits | ||||||||||||||||
2015 | 2014 | 2013 | 2015 | 2014 | 2013 | ||||||||||||
Benefit obligation assumptions | |||||||||||||||||
Discount rate | 4.50 | % | 4.00 | % | 4.75 | % | 5.00 | % | 4.25 | % | 5.25 | % | |||||
Rates of increase in compensation levels | 5.25 | % | 5.25 | % | 5.00 | % | 5.50 | % | 5.25 | % | 5.25 | % | |||||
Net periodic benefit cost assumptions | |||||||||||||||||
Discount rate | 4.00 | % | 4.75 | % | 3.50 | % | 4.25 | % | 5.25 | % | 4.00 | % | |||||
Long-term rate of return on plan assets | 6.75 | % | 6.75 | % | 7.00 | % | N/A | N/A | N/A | ||||||||
Rates of increase in compensation levels | 5.25 | % | 5.00 | % | 4.50 | % | 5.25 | % | 5.25 | % | 4.50 | % | |||||
An annual rate of increase indexed to the Consumer Price Index (CPI) of 1.75% was assumed for purposes of measuring the other postretirement benefit obligation at December 31, 2015, due to a plan amendment effective in 2016 that changed the Company’s annual benefit payments to a per-participant fixed amount, subject to annual escalation based upon CPI. An 8.00% annual rate of increase in the per-capita cost of covered health care benefits for the next year was assumed for purposes of measuring other postretirement benefit obligations at December 31, 2014.
130
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
16. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Plan Assets
Investment Policies and Strategies The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (domestic equity securities, international equity securities, fixed-income securities, real estate, hedge funds, and private equity), with selective exposure to Growth/Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset-allocation percentages by major category are 45%-55% equity securities, 20%-30% fixed income, and up to 25% in a combination of other investments such as real estate, hedge funds, and private equity. Investment managers have full discretion as to investment decisions regarding funds under their management to the extent permitted within investment guidelines.
Although investment managers may, at their discretion and within investment guidelines, invest in Anadarko securities, there are no direct investments in Anadarko securities included in plan assets. There may be, however, indirect investments in Anadarko securities through the plans’ collective fund investments. The expected long-term rate of return on plan assets assumption was determined using the year-end 2015 pension investment balances by asset class and expected long-term asset allocation. The expected return for each asset class reflects capital-market projections formulated using a forward-looking building-block approach while also taking into account historical return trends and current market conditions. Equity returns generally reflect long-term expectations of real earnings growth, dividend yield, and inflation. Returns on fixed-income securities are generally developed based on expected inflation, real bond yield, and risk spread (as appropriate), adjusted for the expected effect that changing yields have on the rate of return. Other asset-class returns are derived from their relationship to the equity and fixed-income markets.
131
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
16. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
The fair value of the Company’s pension plan assets by asset class and input level within the fair-value hierarchy were as follows:
millions | |||||||||||||||
December 31, 2015 | Level 1 | Level 2 | Level 3 | Total | |||||||||||
Investments | |||||||||||||||
Cash and cash equivalents | $ | 5 | $ | 54 | $ | — | $ | 59 | |||||||
Fixed income | |||||||||||||||
Mortgage-backed securities | — | 36 | — | 36 | |||||||||||
U.S. government securities | — | 53 | — | 53 | |||||||||||
Other fixed-income securities (1) | 46 | 236 | — | 282 | |||||||||||
Equity securities | |||||||||||||||
Domestic | 330 | 80 | — | 410 | |||||||||||
International | 130 | 289 | — | 419 | |||||||||||
Other | |||||||||||||||
Real estate | — | 57 | 104 | 161 | |||||||||||
Private equity | — | — | 92 | 92 | |||||||||||
Hedge funds and other alternative strategies | 7 | — | 127 | 134 | |||||||||||
Other | — | 30 | — | 30 | |||||||||||
Total investments (2) | $ | 518 | $ | 835 | $ | 323 | $ | 1,676 | |||||||
Liabilities | |||||||||||||||
Hedge funds and other alternative strategies | $ | (3 | ) | $ | — | $ | — | $ | (3 | ) | |||||
Total liabilities | $ | (3 | ) | $ | — | $ | — | $ | (3 | ) | |||||
December 31, 2014 | |||||||||||||||
Investments | |||||||||||||||
Cash and cash equivalents | $ | 3 | $ | 53 | $ | — | $ | 56 | |||||||
Fixed income | |||||||||||||||
Mortgage-backed securities | — | 51 | — | 51 | |||||||||||
U.S. government securities | — | 56 | — | 56 | |||||||||||
Other fixed-income securities (1) | 48 | 212 | — | 260 | |||||||||||
Equity securities | |||||||||||||||
Domestic | 446 | 130 | — | 576 | |||||||||||
International | 124 | 299 | — | 423 | |||||||||||
Other | |||||||||||||||
Real estate | — | 56 | 94 | 150 | |||||||||||
Private equity | — | — | 84 | 84 | |||||||||||
Hedge funds and other alternative strategies | 9 | — | 126 | 135 | |||||||||||
Other | — | 30 | — | 30 | |||||||||||
Total investments (2) | $ | 630 | $ | 887 | $ | 304 | $ | 1,821 | |||||||
Liabilities | |||||||||||||||
Hedge funds and other alternative strategies | $ | (3 | ) | $ | — | $ | — | $ | (3 | ) | |||||
Total liabilities | $ | (3 | ) | $ | — | $ | — | $ | (3 | ) | |||||
__________________________________________________________________
(1) | Amounts include investments in diversified fixed-income collective investment funds with exposure to mortgage-backed securities, government-issued securities, corporate debt, and other fixed-income securities. |
(2) | Amount excludes receivables and payables, primarily related to Level 1 investments. |
132
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
16. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Investments in securities traded in active markets are measured based on unadjusted quoted prices, which represent Level 1 inputs. Investments based on Level 2 inputs include direct investments in corporate debt and other fixed-income securities as well as shares of open-end mutual funds or similar investment vehicles that do not have a readily determinable fair value but are valued at the net asset value per share (NAV). For such funds, the NAV is the value at which investors transact with the fund, and is determined by the fund based on the estimated fair values of the underlying fund assets. Fair value of investments included as Level 3 inputs generally also reflect investments valued at fund NAVs, but, unlike investments characteristic of Level 2 fair-value measurements, such plan assets have significant liquidity restrictions or other features that are not reflected in NAV.
The following summarizes changes in the fair value of investments based on Level 3 inputs:
millions | Hedge Funds and Other Alternative Strategies | Private Equity | Real Estate | Total | |||||||||||
Balance at January 1, 2014 | $ | 79 | $ | 72 | $ | 86 | $ | 237 | |||||||
Acquisitions (dispositions), net | 42 | — | 2 | 44 | |||||||||||
Actual return on plan assets | |||||||||||||||
Relating to assets sold during the reporting period | 2 | 5 | — | 7 | |||||||||||
Relating to assets still held at the reporting date | 3 | 7 | 6 | 16 | |||||||||||
Balance at December 31, 2014 | $ | 126 | $ | 84 | $ | 94 | $ | 304 | |||||||
Acquisitions (dispositions), net | 1 | (4 | ) | 2 | (1 | ) | |||||||||
Actual return on plan assets | |||||||||||||||
Relating to assets sold during the reporting period | — | 11 | — | 11 | |||||||||||
Relating to assets still held at the reporting date | — | 1 | 8 | 9 | |||||||||||
Balance at December 31, 2015 | $ | 127 | $ | 92 | $ | 104 | $ | 323 | |||||||
Risks and Uncertainties The plan assets include various investment securities that are exposed to various risks such as interest-rate, credit, and market risks. Due to the level of risk associated with certain investment securities, it is possible that changes in the values of investment securities could significantly impact the plan assets.
The plan assets may include securities with contractual cash flows such as asset-backed securities, collateralized mortgage obligations, and commercial mortgage-backed securities, including securities backed by subprime mortgage loans. The value, liquidity, and related income of those securities are sensitive to changes in economic conditions, including real estate values, delinquencies or defaults, or both, and may be adversely affected by shifts in the market’s perception of the issuers and changes in interest rates.
133
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
16. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Cash Contributions and Expected Benefit Payments While reported benefit obligations exceed the fair value of pension and other postretirement plan assets at December 31, 2015, the Company monitors the status of its funded pension plans to ensure that plan funds are sufficient to continue paying benefits. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments.
The following summarizes the Company’s contributions for 2015 and expected contributions for 2016:
millions | Expected 2016 | 2015 | |||||
Funded pension plans | $ | 5 | $ | 4 | |||
Unfunded pension plans | 25 | 39 | |||||
Unfunded other postretirement plans | 16 | 15 | |||||
Total | $ | 46 | $ | 58 | |||
The following summarizes estimated benefit payments for the next ten years, including benefit increases due to continuing employee service:
millions | Pension Benefit Payments | Other Benefit Payments | |||||
2016 | $ | 171 | $ | 16 | |||
2017 | 197 | 17 | |||||
2018 | 194 | 17 | |||||
2019 | 214 | 17 | |||||
2020 | 209 | 18 | |||||
2021-2025 | 1,199 | 92 | |||||
Defined-Contribution Plans The Company maintains several defined-contribution benefit plans, the most significant of which is the Anadarko Employee Savings Plan (ESP). All regular employees of the Company on its U.S. payroll are eligible to participate in the ESP by making elective contributions that are matched by the Company, subject to certain limitations. The Company recognized expense of $76 million for both 2015 and 2014, and $78 million for 2013, related to these plans.
134
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
17. Stockholders’ Equity
Common Stock The following summarizes the changes in the Company’s outstanding shares of common stock:
millions | 2015 | 2014 | 2013 | |||||
Shares of common stock issued | ||||||||
Shares at January 1 | 526 | 523 | 519 | |||||
Exercise of stock options | 1 | 2 | 2 | |||||
Issuance of restricted stock | 1 | 1 | 2 | |||||
Shares at December 31 | 528 | 526 | 523 | |||||
Shares of common stock held in treasury | ||||||||
Shares at January 1 | 19 | 19 | 18 | |||||
Shares received for restricted stock vested and options exercised | 1 | — | 1 | |||||
Shares at December 31 | 20 | 19 | 19 | |||||
Shares of common stock outstanding at December 31 | 508 | 507 | 504 | |||||
The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and TEUs, if the inclusion of these items is dilutive.
The following provides a reconciliation between basic and diluted EPS attributable to common stockholders for the years ended December 31:
millions except per-share amounts | 2015 | 2014 | 2013 | ||||||||
Net income (loss) | |||||||||||
Net income (loss) attributable to common stockholders | $ | (6,692 | ) | $ | (1,750 | ) | $ | 801 | |||
Less distributions on participating securities | 3 | 4 | 2 | ||||||||
Less undistributed income allocated to participating securities | — | — | 4 | ||||||||
Basic | $ | (6,695 | ) | $ | (1,754 | ) | $ | 795 | |||
Diluted | $ | (6,695 | ) | $ | (1,754 | ) | $ | 795 | |||
Shares | |||||||||||
Average number of common shares outstanding—basic | 508 | 506 | 502 | ||||||||
Dilutive effect of stock options | — | — | 3 | ||||||||
Average number of common shares outstanding—diluted | 508 | 506 | 505 | ||||||||
Excluded due to anti-dilutive effect | 11 | 11 | 4 | ||||||||
Net income (loss) per common share | |||||||||||
Basic | $ | (13.18 | ) | $ | (3.47 | ) | $ | 1.58 | |||
Diluted | $ | (13.18 | ) | $ | (3.47 | ) | $ | 1.58 | |||
135
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
18. Accumulated Other Comprehensive Income (Loss)
The following summarizes the after-tax changes in the balances of accumulated other comprehensive income (loss):
millions | Interest-rate Derivatives Previously Subject to Hedge Accounting | Pension and Other Postretirement Plans | Total | ||||||||
Balance at December 31, 2012 | $ | (61 | ) | $ | (579 | ) | $ | (640 | ) | ||
Other comprehensive income (loss), before reclassifications | — | 264 | 264 | ||||||||
Reclassifications to Consolidated Statement of Income | 7 | 84 | 91 | ||||||||
Net other comprehensive income (loss) | 7 | 348 | 355 | ||||||||
Balance at December 31, 2013 | $ | (54 | ) | $ | (231 | ) | $ | (285 | ) | ||
Other comprehensive income (loss), before reclassifications | — | (256 | ) | (256 | ) | ||||||
Reclassifications to Consolidated Statement of Income | 6 | 18 | 24 | ||||||||
Net other comprehensive income (loss) | 6 | (238 | ) | (232 | ) | ||||||
Balance at December 31, 2014 | $ | (48 | ) | $ | (469 | ) | $ | (517 | ) | ||
Other comprehensive income (loss), before reclassifications | — | 87 | 87 | ||||||||
Reclassifications to Consolidated Statement of Income | 6 | 41 | 47 | ||||||||
Net other comprehensive income (loss) | 6 | 128 | 134 | ||||||||
Balance at December 31, 2015 | $ | (42 | ) | $ | (341 | ) | $ | (383 | ) | ||
19. Share-Based Compensation
At December 31, 2015, 16 million shares of the 31 million shares of Anadarko common stock originally authorized for awards under active share-based compensation plans remained available for future issuance. The Company generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted. The following summarizes share-based compensation expense for the years ended December 31:
millions | 2015 | 2014 | 2013 | ||||||||
Restricted stock | $ | 157 | $ | 144 | $ | 122 | |||||
Stock options | 19 | 21 | 27 | ||||||||
Other equity-classified awards | 1 | 1 | 1 | ||||||||
Value creation plan | (4 | ) | 136 | — | |||||||
Performance-based unit awards | (1 | ) | 23 | 4 | |||||||
Other liability-classified awards | — | — | 1 | ||||||||
Pretax compensation expense | $ | 172 | $ | 325 | $ | 155 | |||||
Income tax benefit | $ | 64 | $ | 120 | $ | 57 | |||||
Cash flows from financing activities included excess tax benefits related to share-based compensation of $6 million in 2015, $22 million in 2014, and $11 million in 2013. Cash received from stock option exercises was $28 million in 2015, $99 million in 2014, and $135 million in 2013.
136
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
19. Share-Based Compensation (Continued)
Equity-Classified Awards
Restricted Stock Certain employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock awards have the same rights as a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. A restricted stock unit is equivalent to a restricted stock award except that unit holders do not have the right to vote. Restricted stock vests over service periods ranging from the date of grant generally up to three years and is not considered issued and outstanding until vested.
Non-employee directors are granted deferred shares, which are also considered restricted stock, that are held in a grantor trust by the Company until payable. Non-employee directors may receive these shares in a lump-sum payment or in annual installments.
The following summarizes the Company’s restricted stock activity:
Shares (millions) | Weighted-Average Grant-Date Fair Value (per share) | |||||
Non-vested at January 1, 2015 | 3.60 | $ | 85.31 | |||
Granted | 2.35 | $ | 79.40 | |||
Vested | (1.76 | ) | $ | 84.18 | ||
Forfeited | (0.21 | ) | $ | 84.34 | ||
Non-vested at December 31, 2015 | 3.98 | $ | 82.39 | |||
The weighted-average grant-date fair value per share of restricted stock granted was $87.42 during 2014 and $84.17 during 2013. The total fair value of restricted shares vested was $141 million during 2015, $132 million during 2014, and $110 million during 2013, based on the market price at the vesting date. At December 31, 2015, total unrecognized compensation cost related to restricted stock of $213 million is expected to be recognized over a weighted-average remaining service period of 1.9 years.
137
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
19. Share-Based Compensation (Continued)
Stock Options Certain employees may be granted nonqualified options to purchase shares of Anadarko common stock with an exercise price equal to, or greater than, the fair market value of Anadarko common stock on the date of grant. These stock options generally vest over three years from the date of grant and terminate at the earlier of the date of exercise or seven years from the date of grant.
The fair value of stock option awards is determined using the Black-Scholes option-pricing model with the following assumptions:
• | Expected life—Based on historical exercise behavior. |
• | Volatility—Based on an average of historical volatility over the expected life of an option and the 12-month average implied volatility. |
• | Risk-free interest rates—Based on the U.S. Treasury rate over the expected life of an option. |
• | Dividend yield—Based on a 12-month average dividend yield, taking into account the Company’s expected dividend policy over the expected life of an option. |
• | Expected forfeiture—Based on historical forfeiture experience. |
The Company used the following weighted-average assumptions to estimate the fair value of stock options granted:
2015 | 2014 | 2013 | ||||||||||||
Weighted-average grant-date fair value | $ | 18.18 | $ | 23.55 | $ | 26.27 | ||||||||
Assumptions | ||||||||||||||
Expected option life—years | 4.9 | 4.9 | 4.8 | |||||||||||
Volatility | 32.4 | % | 29.9 | % | 33.9 | % | ||||||||
Risk-free interest rate | 1.4 | % | 1.6 | % | 1.3 | % | ||||||||
Dividend yield | 1.4 | % | 1.1 | % | 0.8 | % | ||||||||
The following summarizes the Company’s stock option activity:
Shares (millions) | Weighted- Average Exercise Price (per share) | Weighted- Average Remaining Contractual Term (years) | Aggregate Intrinsic Value (millions) | |||||||||
Outstanding at January 1, 2015 | 6.79 | $ | 69.96 | |||||||||
Granted | 1.16 | $ | 69.37 | |||||||||
Exercised (1) | (0.66 | ) | $ | 42.37 | ||||||||
Forfeited or expired | (0.24 | ) | $ | 87.08 | ||||||||
Outstanding at December 31, 2015 | 7.05 | $ | 71.86 | 3.40 | $ | 13.9 | ||||||
Vested or expected to vest at December 31, 2015 | 6.98 | $ | 71.77 | 3.37 | $ | 13.9 | ||||||
Exercisable at December 31, 2015 | 5.07 | $ | 69.08 | 2.28 | $ | 13.9 | ||||||
__________________________________________________________________
(1) | The total intrinsic value of stock options exercised was $23 million during 2015, $88 million during 2014, and $80 million during 2013, based on the difference between the market price at the exercise date and the exercise price. |
At December 31, 2015, total unrecognized compensation cost related to stock options of $38 million is expected to be recognized over a weighted-average remaining service period of 2.2 years.
138
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
19. Share-Based Compensation (Continued)
Liability-Classified Awards
Value Creation Plan As a part of its employee compensation program, the Company offered an incentive compensation program that provided non-officer employees the opportunity to earn cash bonus awards based on the Company’s TSR for the year, compared to the TSR of a predetermined group of peer companies. The Company paid $134 million during 2015 related to the plan and zero during 2014 and 2013. The Value Creation Plan was discontinued as an active plan beginning in 2015.
Performance-Based Unit Awards Certain officers of the Company were provided Performance Unit Award Agreements with two- and three-year performance periods. The vesting of these units is based on comparing the Company’s TSR to the TSR of a predetermined group of peer companies over the specified performance period. Each performance unit represents the value of one share of the Company’s common stock. Following the end of each performance period, the value of the vested performance units, if any, is paid in cash. The Company paid $9 million related to vested performance units in 2015, $12 million in 2014, and $15 million in 2013. At December 31, 2015, the Company’s liability under Performance Unit Award Agreements was $16 million, with total unrecognized compensation cost related to these awards of $27 million expected to be recognized over a weighted-average remaining performance period of 2.4 years.
20. Noncontrolling Interests
WGP, a publicly traded consolidated subsidiary, is a limited partnership that owns interests in WES. In 2015, Anadarko sold 2.3 million WGP common units to the public and raised net proceeds of $130 million and in 2014 sold approximately 6 million WGP common units to the public and raised net proceeds of $335 million. In June 2015, Anadarko issued 9.2 million TEUs, which include an equity component that may be settled in WGP common units. For additional disclosure of the TEU effect on noncontrolling interests, see Note 10—Tangible Equity Units. 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. The remaining 12.7% limited partner interest in WGP was owned by the public.
WES, a publicly traded consolidated subsidiary, is a limited partnership that acquires, owns, develops, and operates midstream assets. WES issued approximately 874 thousand common units to the public and raised net proceeds of $57 million in 2015, issued approximately 10 million common units to the public and raised net proceeds of $691 million in 2014, and issued approximately 12 million common units to the public and raised net proceeds of $725 million in 2013. In addition, WES issued 11 million Class C units to Anadarko in 2014 to partially fund the DBM acquisition. These units will receive quarterly distributions in the form of additional Class C units until the end of 2017, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. During 2015, WES distributed 498 thousand Class C units to Anadarko. 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’ ownership of common and Class C units. The remaining 55.1% limited partner interest in WES was owned by the public.
139
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
21. Supplemental Cash Flow Information
For the year ended December 31, 2015, the Company’s Consolidated Statement of Cash Flows includes an $881 million increase in tax receivable related to the Tronox settlement included in (increase) decrease in accounts receivable, offset by an $881 million uncertain tax position included in other items, net. The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities, for the years ended December 31:
millions | 2015 | 2014 | 2013 | ||||||||
Cash paid (received) | |||||||||||
Interest, net of amounts capitalized(1) | $ | 2,019 | $ | 689 | $ | 627 | |||||
Income taxes, net of refunds | 26 | 956 | 169 | ||||||||
Non-cash investing activities | |||||||||||
Fair value of properties and equipment from non-cash transactions | $ | 178 | $ | 18 | $ | 62 | |||||
Asset retirement cost additions | 273 | 348 | 297 | ||||||||
Accruals of property, plant, and equipment | 754 | 1,177 | 1,446 | ||||||||
Net liabilities assumed (divested) in acquisitions and divestitures | (114 | ) | (92 | ) | (80 | ) | |||||
Property insurance receivable | 49 | — | — | ||||||||
Non-cash investing and financing activities | |||||||||||
Capital lease obligation | $ | — | $ | 13 | $ | 8 | |||||
Floating production, storage, and offloading vessel construction period obligation | 59 | 128 | 17 | ||||||||
__________________________________________________________________
(1) Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.
22. Segment Information
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 oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces oil, condensate, natural gas, and NGLs, and plans for the development and operation of the Company’s LNG project in Mozambique. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The midstream reporting segment consists of two operating segments, WES and other midstream, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells much of Anadarko’s oil, natural-gas, and NGLs production, as well as third-party purchased volumes.
140
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
22. Segment Information (Continued)
To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; gains (losses) on divestitures, net; exploration expense; DD&A; impairments; interest expense; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; and certain items not related to the Company’s normal operations, less net income (loss) attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included other operating expenses such as Deepwater Horizon settlement and related costs and the Algeria exceptional profits tax settlement, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX excludes gains (losses) on divestitures, net and exploration expense as they are not indicators of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income (loss) attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.
Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders. Adjusted EBITDAX as defined by Anadarko may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes for the years ended December 31:
millions | 2015 | 2014 | 2013 | ||||||||
Income (loss) before income taxes | $ | (9,689 | ) | $ | 54 | $ | 2,106 | ||||
(Gains) losses on divestitures, net | 1,022 | (1,891 | ) | 470 | |||||||
Exploration expense | 2,644 | 1,639 | 1,329 | ||||||||
DD&A | 4,603 | 4,550 | 3,927 | ||||||||
Impairments | 5,075 | 836 | 794 | ||||||||
Interest expense | 825 | 772 | 686 | ||||||||
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives | 235 | 578 | (307 | ) | |||||||
Other operating expense | 74 | 97 | 48 | ||||||||
Tronox-related contingent loss | 5 | 4,360 | 850 | ||||||||
Certain other nonoperating items | 22 | 22 | 110 | ||||||||
Less net income (loss) attributable to noncontrolling interests | (120 | ) | 187 | 140 | |||||||
Consolidated Adjusted EBITDAX | $ | 4,936 | $ | 10,830 | $ | 9,873 | |||||
141
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
22. Segment Information (Continued)
The Company’s accounting policies for individual segments are the same as those described in the summary of significant accounting policies, with the following exception: certain intersegment commodity contracts may meet the GAAP definition of a derivative instrument, which would be accounted for at fair value under GAAP. However, Anadarko does not recognize any mark-to-market adjustments on such intersegment arrangements. Additionally, intersegment asset transfers are accounted for at historical cost basis, and do not give rise to gain or loss recognition.
Information presented below as “Other and Intersegment Eliminations” includes corporate costs, results from hard-minerals royalties, and net cash from settlement of commodity derivatives. The following summarizes selected financial information for Anadarko’s reporting segments:
millions | Oil and Gas Exploration & Production | Midstream | Marketing | Other and Intersegment Eliminations | Total | ||||||||||||||
2015 | |||||||||||||||||||
Sales revenues | $ | 4,734 | $ | 727 | $ | 4,025 | $ | — | $ | 9,486 | |||||||||
Intersegment revenues | 3,178 | 1,207 | (3,476 | ) | (909 | ) | — | ||||||||||||
Other | — | — | — | 234 | 234 | ||||||||||||||
Total revenues and other (1) | 7,912 | 1,934 | 549 | (675 | ) | 9,720 | |||||||||||||
Operating costs and expenses (2) | 3,456 | 998 | 743 | (86 | ) | 5,111 | |||||||||||||
Net cash from settlement of commodity derivatives | — | — | — | (335 | ) | (335 | ) | ||||||||||||
Other (income) expense, net (3) | — | — | — | 127 | 127 | ||||||||||||||
Net income (loss) attributable to noncontrolling interests | — | (120 | ) | — | — | (120 | ) | ||||||||||||
Total expenses and other | 3,456 | 878 | 743 | (294 | ) | 4,783 | |||||||||||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement | — | — | (1 | ) | — | (1 | ) | ||||||||||||
Adjusted EBITDAX | $ | 4,456 | $ | 1,056 | $ | (195 | ) | $ | (381 | ) | $ | 4,936 | |||||||
Net properties and equipment | $ | 25,742 | $ | 5,876 | $ | — | $ | 2,133 | $ | 33,751 | |||||||||
Capital expenditures | $ | 5,029 | $ | 770 | $ | — | $ | 89 | $ | 5,888 | |||||||||
Goodwill | $ | 4,945 | $ | 450 | $ | — | $ | — | $ | 5,395 | |||||||||
__________________________________________________________________
(1) | Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX. |
(2) | Operating costs and expenses excludes exploration expense, DD&A, impairments, and other operating expense since these expenses are excluded from Adjusted EBITDAX. |
(3) | Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX. |
142
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
22. Segment Information (Continued)
millions | Oil and Gas Exploration & Production | Midstream | Marketing | Other and Intersegment Eliminations | Total | ||||||||||||||
2014 | |||||||||||||||||||
Sales revenues | $ | 8,603 | $ | 484 | $ | 7,288 | $ | — | $ | 16,375 | |||||||||
Intersegment revenues | 6,225 | 1,338 | (6,771 | ) | (792 | ) | — | ||||||||||||
Other | — | — | — | 204 | 204 | ||||||||||||||
Total revenues and other (1) | 14,828 | 1,822 | 517 | (588 | ) | 16,579 | |||||||||||||
Operating costs and expenses (2) | 4,216 | 972 | 740 | 17 | 5,945 | ||||||||||||||
Net cash from settlement of commodity derivatives | — | — | — | (377 | ) | (377 | ) | ||||||||||||
Other (income) expense, net (3) | — | — | — | (2 | ) | (2 | ) | ||||||||||||
Net income (loss) attributable to noncontrolling interests | — | 187 | — | — | 187 | ||||||||||||||
Total expenses and other | 4,216 | 1,159 | 740 | (362 | ) | 5,753 | |||||||||||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement | — | — | 4 | — | 4 | ||||||||||||||
Adjusted EBITDAX | $ | 10,612 | $ | 663 | $ | (219 | ) | $ | (226 | ) | $ | 10,830 | |||||||
Net properties and equipment | $ | 32,717 | $ | 6,697 | $ | — | $ | 2,175 | $ | 41,589 | |||||||||
Capital expenditures | $ | 7,934 | $ | 1,149 | $ | — | $ | 173 | $ | 9,256 | |||||||||
Goodwill | $ | 5,123 | $ | 453 | $ | — | $ | — | $ | 5,576 | |||||||||
2013 | |||||||||||||||||||
Sales revenues | $ | 7,090 | $ | 387 | $ | 7,390 | $ | — | $ | 14,867 | |||||||||
Intersegment revenues | 6,405 | 1,105 | (6,859 | ) | (651 | ) | — | ||||||||||||
Other | — | — | — | 184 | 184 | ||||||||||||||
Total revenues and other (1) | 13,495 | 1,492 | 531 | (467 | ) | 15,051 | |||||||||||||
Operating costs and expenses (2) | 3,635 | 843 | 652 | 20 | 5,150 | ||||||||||||||
Net cash from settlement of commodity derivatives | — | — | — | (95 | ) | (95 | ) | ||||||||||||
Other (income) expense, net (3) | — | — | — | (21 | ) | (21 | ) | ||||||||||||
Net income (loss) attributable to noncontrolling interests | — | 140 | — | — | 140 | ||||||||||||||
Total expenses and other | 3,635 | 983 | 652 | (96 | ) | 5,174 | |||||||||||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement | — | — | (4 | ) | — | (4 | ) | ||||||||||||
Adjusted EBITDAX | $ | 9,860 | $ | 509 | $ | (125 | ) | $ | (371 | ) | $ | 9,873 | |||||||
Net properties and equipment | $ | 33,409 | $ | 5,408 | $ | 9 | $ | 2,103 | $ | 40,929 | |||||||||
Capital expenditures | $ | 7,008 | $ | 1,248 | $ | — | $ | 267 | $ | 8,523 | |||||||||
Goodwill | $ | 5,317 | $ | 175 | $ | — | $ | — | $ | 5,492 | |||||||||
__________________________________________________________________
(1) | Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX. |
(2) | Operating costs and expenses excludes exploration expense, DD&A, impairments, and other operating expense since these expenses are excluded from Adjusted EBITDAX. |
(3) | Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX. |
143
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
22. Segment Information (Continued)
The following represents Anadarko’s sales revenues (based on the origin of the sales) and net properties and equipment by geographic area:
Years Ended December 31, | |||||||||||
millions | 2015 | 2014 | 2013 | ||||||||
Sales Revenues | |||||||||||
United States | $ | 7,819 | $ | 13,083 | $ | 11,290 | |||||
Algeria | 1,189 | 2,435 | 2,184 | ||||||||
Other International | 478 | 857 | 1,393 | ||||||||
Total sales revenues | $ | 9,486 | $ | 16,375 | $ | 14,867 | |||||
December 31, | |||||||
millions | 2015 | 2014 | |||||
Net Properties and Equipment | |||||||
United States | $ | 29,625 | $ | 37,186 | |||
Algeria | 1,271 | 1,431 | |||||
Other International | 2,855 | 2,972 | |||||
Total net properties and equipment | $ | 33,751 | $ | 41,589 | |||
Major Customers In 2015 and 2014, there were no sales to customers that exceeded 10% of the Company’s total sales revenues. Sales to Total S.A. were $2.0 billion in 2013. These amounts are included in the oil and gas exploration and production reporting segment.
144
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
The unaudited supplemental information on oil and gas exploration and production activities for 2015, 2014, and 2013 has been presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas and the Securities and Exchange Commission’s final rule, Modernization of Oil and Gas Reporting. 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. The Company sold its Chinese subsidiary during 2014.
Oil and Gas Reserves
The following reserves disclosures reflect estimates of proved reserves, proved developed reserves, and proved undeveloped reserves, net of third-party royalty interests, of oil, condensate, natural gas, and natural-gas liquids (NGLs) owned at each year end and changes in proved reserves during each of the last three years. Oil, condensate, and NGLs volumes are presented in millions of barrels (MMBbls) and natural-gas volumes are presented in billions of cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch. 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.
Reserves for international locations are calculated in accordance with the terms of governing agreements. The international reserves include estimated quantities allocated to Anadarko for recovery of costs and income taxes and Anadarko’s net equity share after recovery of such costs.
The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. The results of infill drilling are treated as positive revisions due to increases to expected recovery. Other revisions are due to changes in, among other things, development plans, reservoir performance, commodity prices, economic conditions, and governmental restrictions.
The prices below were used to compute the information presented in the following tables and are adjusted only for fixed and determinable amounts under provisions in existing contracts:
Oil and Condensate per Bbl | Natural Gas per MMBtu | NGLs per Bbl (1) | ||||||||||
December 31, 2015 | $ | 50.28 | $ | 2.59 | $ | 19.47 | ||||||
December 31, 2014 | $ | 94.99 | $ | 4.35 | $ | 45.25 | ||||||
December 31, 2013 | $ | 96.78 | $ | 3.67 | N/A | |||||||
__________________________________________________________________
(1) | The benchmark price for NGLs was previously the same as that for oil, but was converted to a NGLs-specific price beginning in 2014. |
MMBtu—million British thermal units
Bbl—barrel
145
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Oil and Gas Reserves (Continued)
Oil and Condensate (MMBbls) | Natural Gas (Bcf) | ||||||||||||||||
United States | International | Total | United States | International | Total | ||||||||||||
Proved Reserves | |||||||||||||||||
December 31, 2012 | 511 | 256 | 767 | 8,329 | — | 8,329 | |||||||||||
Revisions of prior estimates | 96 | 21 | 117 | 1,276 | — | 1,276 | |||||||||||
Extensions, discoveries, and other additions | 52 | 14 | 66 | 416 | — | 416 | |||||||||||
Purchases in place | 1 | — | 1 | 153 | — | 153 | |||||||||||
Sales in place | (10 | ) | — | (10 | ) | (4 | ) | — | (4 | ) | |||||||
Production | (58 | ) | (32 | ) | (90 | ) | (965 | ) | — | (965 | ) | ||||||
December 31, 2013 | 592 | 259 | 851 | 9,205 | — | 9,205 | |||||||||||
Revisions of prior estimates | 167 | 18 | 185 | 710 | 31 | 741 | |||||||||||
Extensions, discoveries, and other additions | 25 | — | 25 | 196 | — | 196 | |||||||||||
Purchases in place | — | — | — | — | — | — | |||||||||||
Sales in place | (6 | ) | (17 | ) | (23 | ) | (492 | ) | — | (492 | ) | ||||||
Production | (74 | ) | (35 | ) | (109 | ) | (951 | ) | — | (951 | ) | ||||||
December 31, 2014 | 704 | 225 | 929 | 8,668 | 31 | 8,699 | |||||||||||
Revisions of prior estimates | 2 | (6 | ) | (4 | ) | (888 | ) | 4 | (884 | ) | |||||||
Extensions, discoveries, and other additions | 15 | — | 15 | 60 | — | 60 | |||||||||||
Purchases in place | — | — | — | 8 | — | 8 | |||||||||||
Sales in place | (111 | ) | — | (111 | ) | (1,003 | ) | — | (1,003 | ) | |||||||
Production | (85 | ) | (31 | ) | (116 | ) | (854 | ) | (5 | ) | (859 | ) | |||||
December 31, 2015 | 525 | 188 | 713 | 5,991 | 30 | 6,021 | |||||||||||
Proved Developed Reserves | |||||||||||||||||
December 31, 2012 | 318 | 208 | 526 | 6,445 | — | 6,445 | |||||||||||
December 31, 2013 | 347 | 202 | 549 | 7,120 | — | 7,120 | |||||||||||
December 31, 2014 | 352 | 190 | 542 | 6,635 | 27 | 6,662 | |||||||||||
December 31, 2015 | 332 | 159 | 491 | 5,184 | 30 | 5,214 | |||||||||||
Proved Undeveloped Reserves | |||||||||||||||||
December 31, 2012 | 193 | 48 | 241 | 1,884 | — | 1,884 | |||||||||||
December 31, 2013 | 245 | 57 | 302 | 2,085 | — | 2,085 | |||||||||||
December 31, 2014 | 352 | 35 | 387 | 2,033 | 4 | 2,037 | |||||||||||
December 31, 2015 | 193 | 29 | 222 | 807 | — | 807 | |||||||||||
146
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Oil and Gas Reserves (Continued)
NGLs (MMBbls) | Total (MMBOE) | ||||||||||||||||
United States | International | Total | United States | International | Total | ||||||||||||
Proved Reserves | |||||||||||||||||
December 31, 2012 | 393 | 12 | 405 | 2,292 | 268 | 2,560 | |||||||||||
Revisions of prior estimates (1) | 17 | — | 17 | 326 | 21 | 347 | |||||||||||
Extensions, discoveries, and other additions | 10 | — | 10 | 131 | 14 | 145 | |||||||||||
Purchases in place | 9 | — | 9 | 36 | — | 36 | |||||||||||
Sales in place | (1 | ) | — | (1 | ) | (12 | ) | — | (12 | ) | |||||||
Production | (33 | ) | — | (33 | ) | (252 | ) | (32 | ) | (284 | ) | ||||||
December 31, 2013 | 395 | 12 | 407 | 2,521 | 271 | 2,792 | |||||||||||
Revisions of prior estimates (1) | 129 | 2 | 131 | 414 | 25 | 439 | |||||||||||
Extensions, discoveries, and other additions | 5 | — | 5 | 63 | — | 63 | |||||||||||
Purchases in place | — | — | — | — | — | — | |||||||||||
Sales in place | (19 | ) | — | (19 | ) | (107 | ) | (17 | ) | (124 | ) | ||||||
Production | (44 | ) | (1 | ) | (45 | ) | (276 | ) | (36 | ) | (312 | ) | |||||
December 31, 2014 | 466 | 13 | 479 | 2,615 | 243 | 2,858 | |||||||||||
Revisions of prior estimates (1) | (99 | ) | 4 | (95 | ) | (245 | ) | (1 | ) | (246 | ) | ||||||
Extensions, discoveries, and other additions | 4 | — | 4 | 29 | — | 29 | |||||||||||
Purchases in place | — | — | — | 1 | — | 1 | |||||||||||
Sales in place | (1 | ) | — | (1 | ) | (279 | ) | — | (279 | ) | |||||||
Production | (45 | ) | (2 | ) | (47 | ) | (272 | ) | (34 | ) | (306 | ) | |||||
December 31, 2015 | 325 | 15 | 340 | 1,849 | 208 | 2,057 | |||||||||||
Proved Developed Reserves | |||||||||||||||||
December 31, 2012 | 283 | — | 283 | 1,675 | 208 | 1,883 | |||||||||||
December 31, 2013 | 268 | — | 268 | 1,801 | 202 | 2,003 | |||||||||||
December 31, 2014 | 304 | 13 | 317 | 1,762 | 207 | 1,969 | |||||||||||
December 31, 2015 | 257 | 15 | 272 | 1,453 | 179 | 1,632 | |||||||||||
Proved Undeveloped Reserves | |||||||||||||||||
December 31, 2012 | 110 | 12 | 122 | 617 | 60 | 677 | |||||||||||
December 31, 2013 | 127 | 12 | 139 | 720 | 69 | 789 | |||||||||||
December 31, 2014 | 162 | — | 162 | 853 | 36 | 889 | |||||||||||
December 31, 2015 | 68 | — | 68 | 396 | 29 | 425 | |||||||||||
__________________________________________________________________
(1) | Revisions of prior estimates include the effects of new infill drilling, changes in commodity prices, and other updates, including changes in economic conditions, changes in reservoir performance, and changes to development plans. Additions generated by Anadarko’s infill drilling programs were 89 MMBOE for 2015, 577 MMBOE for 2014, and 410 MMBOE for 2013. |
147
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Total proved reserves decreased by 801 MMBOE in 2015 primarily due to the following:
• | Revisions of prior estimates Prior estimates of proved reserves were revised downward by 246 MMBOE. Negative revisions of 624 MMBOE were due to the decline in commodity prices and include a reduction to NGLs reserves of 43 MMBOE associated with price-induced ethane rejection. The negative price-related revisions were partially offset by a net increase of 378 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 Rocky Mountains Region (Rockies), and decreases primarily associated with updates to development plans to align with the current economic environment. |
• | Extensions and discoveries Proved reserves increased by 29 MMBOE through the extension of proved acreage, primarily as a result of successful drilling in the Wolfcamp shale play in the Southern and Appalachia Region. Although shale plays represented only 20% of the Company’s total proved reserves at December 31, 2015, growth in the shale plays contributed almost all of the total extensions and discoveries. |
• | Sales in place Proved developed reserves decreased by 238 MMBOE primarily associated with the divestiture of a portion of the Company’s East Texas assets in the Southern and Appalachia Region and enhanced oil recovery and coalbed methane assets in the Rockies. Proved undeveloped reserves decreased by 41 MMBOE primarily associated with divestiture activities in the Rockies. |
Total proved reserves increased by 66 MMBOE in 2014 primarily due to the following:
• | Revisions of prior estimates Proved reserves increased by 577 MMBOE related to successful infill drilling in large onshore areas such as the Wattenberg area and the Eagleford and Haynesville shales. Partially offsetting these positive infill revisions was a net decrease of 138 MMBOE, primarily associated with the optimization of horizontal drilling locations and the discontinuation of vertical well workover plans in the Wattenberg area. |
• | Extensions and discoveries Proved reserves increased by 63 MMBOE primarily as a result of successful drilling in the Marcellus and Wolfcamp shale plays. Although shale plays represented only 17% of the Company’s total proved reserves at December 31, 2014, growth in the shale plays contributed 49 MMBOE, or 78%, of the total extensions and discoveries. |
• | Sales in place Proved developed reserves decreased by 69 MMBOE and proved undeveloped reserves decreased by 55 MMBOE due to divestitures, including the divestiture of the Company’s interest in the Pinedale/Jonah assets in Wyoming, the Company’s Chinese subsidiary, and a portion of the Company’s working interest in the East Texas Chalk area. |
Total proved reserves increased by 232 MMBOE in 2013 primarily due to the following:
• | Revisions of prior estimates Proved reserves increased by 410 MMBOE related to successful infill drilling, primarily in large onshore areas such as Wattenberg, Greater Natural Buttes, and the Eagleford shale, and 30 MMBOE resulting from improved oil and natural-gas prices. Partially offsetting these positive revisions were decreases of 53 MMBbls of NGLs reserves due to lower ethane prices and 40 MMBOE due to other non-price-related revisions primarily in the Rockies. |
• | Extensions and discoveries Proved reserves increased by 145 MMBOE as the result of successful drilling primarily in the Marcellus shale and the Gulf of Mexico. Although shale plays represented only 13% of the Company’s total proved reserves at December 31, 2013, growth in the shale plays contributed 70 MMBOE, or 48%, of the total extensions and discoveries. |
• | Purchases in place Proved reserves increased by 36 MMBOE due to acquisitions related to domestic assets almost exclusively in the Rockies. |
• | Sales in place Proved undeveloped reserves decreased by 12 MMBOE primarily due to a partial sale of a working interest in the Gulf of Mexico Heidelberg development project. |
148
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Capitalized Costs
Capitalized costs include the cost of properties, equipment, and facilities for oil and natural-gas producing activities. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. Capitalized costs associated with activities of the Company’s midstream and marketing reporting segments, liquefied natural gas (LNG) facilities costs, and other corporate activities are not included.
millions | United States | International | Total | ||||||||
December 31, 2015 | |||||||||||
Capitalized | |||||||||||
Unproved properties | $ | 2,742 | $ | 739 | $ | 3,481 | |||||
Proved properties | 50,275 | 5,472 | 55,747 | ||||||||
53,017 | 6,211 | 59,228 | |||||||||
Less accumulated DD&A | 31,366 | 2,281 | 33,647 | ||||||||
Net capitalized costs | $ | 21,651 | $ | 3,930 | $ | 25,581 | |||||
December 31, 2014 | |||||||||||
Capitalized | |||||||||||
Unproved properties | $ | 3,858 | $ | 1,291 | $ | 5,149 | |||||
Proved properties | 53,545 | 4,895 | 58,440 | ||||||||
57,403 | 6,186 | 63,589 | |||||||||
Less accumulated DD&A | 29,055 | 1,902 | 30,957 | ||||||||
Net capitalized costs | $ | 28,348 | $ | 4,284 | $ | 32,632 | |||||
149
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition, exploration, and development activities. Costs incurred also include new asset retirement obligations established in the current year as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities. Costs associated with activities of the Company’s midstream and marketing reporting segments, LNG facilities costs, and other corporate activities are not included.
millions | United States | International | Total | ||||||||
Year Ended December 31, 2015 | |||||||||||
Property acquisitions | |||||||||||
Unproved | $ | 293 | $ | 1 | $ | 294 | |||||
Proved | 81 | — | 81 | ||||||||
Exploration | 503 | 609 | 1,112 | ||||||||
Development | 3,660 | 606 | 4,266 | ||||||||
Total costs incurred | $ | 4,537 | $ | 1,216 | $ | 5,753 | |||||
Year Ended December 31, 2014 | |||||||||||
Property acquisitions | |||||||||||
Unproved | $ | 264 | $ | 19 | $ | 283 | |||||
Proved | 3 | — | 3 | ||||||||
Exploration | 1,095 | 616 | 1,711 | ||||||||
Development | 6,158 | 557 | 6,715 | ||||||||
Total costs incurred | $ | 7,520 | $ | 1,192 | $ | 8,712 | |||||
Year Ended December 31, 2013 | |||||||||||
Property acquisitions | |||||||||||
Unproved | $ | 282 | $ | 45 | $ | 327 | |||||
Proved | 324 | — | 324 | ||||||||
Exploration | 1,031 | 939 | 1,970 | ||||||||
Development | 4,421 | 444 | 4,865 | ||||||||
Total costs incurred | $ | 6,058 | $ | 1,428 | $ | 7,486 | |||||
150
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Results of Operations
Results of operations for producing activities consist of all activities within the oil and gas exploration and production reporting segment. Net revenues from production include only the revenues from the production and sale of oil, condensate, natural gas, and NGLs. Gains (losses) on property dispositions represent net gains or losses on sales of oil and gas properties. Production costs are costs to operate and maintain the Company’s wells, related equipment, and supporting facilities used in oil and gas operations, 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. Exploration expenses include dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining unproved leaseholds. Other operating expense includes Deepwater Horizon settlement and related costs and the Algeria exceptional profits tax settlement, representing the Company’s resolution of the Algeria exceptional profits tax dispute with Sonatrach, which provided for the transfer of $1.7 billion of oil to the Company over a 12-month period ending in mid-2013. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion, and amortization allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.
millions | United States | International | Total | ||||||||
Year Ended December 31, 2015 | |||||||||||
Net revenues from production | |||||||||||
Third-party sales | $ | 4,409 | $ | 673 | $ | 5,082 | |||||
Sales to consolidated affiliates | 2,184 | 994 | 3,178 | ||||||||
Gains (losses) on property dispositions | (976 | ) | (14 | ) | (990 | ) | |||||
5,617 | 1,653 | 7,270 | |||||||||
Production costs | |||||||||||
Oil and gas operating | 815 | 199 | 1,014 | ||||||||
Oil and gas transportation | 1,083 | 34 | 1,117 | ||||||||
Production-related general and administrative expenses | 398 | 11 | 409 | ||||||||
Other taxes | 218 | 270 | 488 | ||||||||
2,514 | 514 | 3,028 | |||||||||
Exploration expenses | 1,447 | 1,197 | 2,644 | ||||||||
Depreciation, depletion, and amortization | 3,785 | 399 | 4,184 | ||||||||
Impairments related to oil and gas properties | 4,033 | — | 4,033 | ||||||||
Other operating expense | 150 | — | 150 | ||||||||
(6,312 | ) | (457 | ) | (6,769 | ) | ||||||
Income tax expense | (2,332 | ) | 252 | (2,080 | ) | ||||||
Results of operations | $ | (3,980 | ) | $ | (709 | ) | $ | (4,689 | ) | ||
151
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Results of Operations (Continued)
millions | United States | International | Total | ||||||||
Year Ended December 31, 2014 | |||||||||||
Net revenues from production | |||||||||||
Third-party sales | $ | 7,425 | $ | 1,518 | $ | 8,943 | |||||
Sales to consolidated affiliates | 4,453 | 1,773 | 6,226 | ||||||||
Gains (losses) on property dispositions | (91 | ) | 1,982 | 1,891 | |||||||
11,787 | 5,273 | 17,060 | |||||||||
Production costs | |||||||||||
Oil and gas operating | 968 | 203 | 1,171 | ||||||||
Oil and gas transportation | 1,084 | 33 | 1,117 | ||||||||
Production-related general and administrative expenses | 394 | 32 | 426 | ||||||||
Other taxes | 652 | 535 | 1,187 | ||||||||
3,098 | 803 | 3,901 | |||||||||
Exploration expenses | 1,218 | 421 | 1,639 | ||||||||
Depreciation, depletion, and amortization | 3,783 | 398 | 4,181 | ||||||||
Impairments related to oil and gas properties | 821 | — | 821 | ||||||||
Other operating expense | 163 | — | 163 | ||||||||
2,704 | 3,651 | 6,355 | |||||||||
Income tax expense | 995 | 979 | 1,974 | ||||||||
Results of operations | $ | 1,709 | $ | 2,672 | $ | 4,381 | |||||
Year Ended December 31, 2013 | |||||||||||
Net revenues from production | |||||||||||
Third-party sales | $ | 6,567 | $ | 856 | $ | 7,423 | |||||
Sales to consolidated affiliates | 3,685 | 2,720 | 6,405 | ||||||||
Gains (losses) on property dispositions | (618 | ) | (3 | ) | (621 | ) | |||||
9,634 | 3,573 | 13,207 | |||||||||
Production costs | |||||||||||
Oil and gas operating | 874 | 218 | 1,092 | ||||||||
Oil and gas transportation | 959 | 22 | 981 | ||||||||
Production-related general and administrative expenses | 332 | 5 | 337 | ||||||||
Other taxes | 569 | 455 | 1,024 | ||||||||
2,734 | 700 | 3,434 | |||||||||
Exploration expenses | 611 | 718 | 1,329 | ||||||||
Depreciation, depletion and amortization | 3,222 | 399 | 3,621 | ||||||||
Impairments related to oil and gas properties | 704 | — | 704 | ||||||||
Other operating expense | 54 | 33 | 87 | ||||||||
2,309 | 1,723 | 4,032 | |||||||||
Income tax expense | 845 | 1,005 | 1,850 | ||||||||
Results of operations | $ | 1,464 | $ | 718 | $ | 2,182 | |||||
152
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Estimates of future net cash flows from proved reserves are computed based on the average beginning-of-the-month prices during the 12-month period for the year. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, and abandonment and dismantlement costs based on existing costs, assuming continuation of existing economic conditions, and by estimated future income tax expense. These estimates also include assumptions about the timing of future production of proved reserves, and timing of future development, production costs, and abandonment and dismantlement. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows, giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense. The 10% discount factor is prescribed by U.S. Generally Accepted Accounting Principles.
The present value of future net cash flows is not an estimate of the fair value of Anadarko’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves, and a discount factor more representative of the time value of money and the risks inherent in producing oil and natural gas. Significant changes in estimated reserves volumes or commodity prices could have a material effect on the Company’s Consolidated Financial Statements.
millions | United States | International | Total | ||||||||
December 31, 2015 | |||||||||||
Future cash inflows | $ | 42,919 | $ | 10,392 | $ | 53,311 | |||||
Future production costs | 21,100 | 3,829 | 24,929 | ||||||||
Future development costs | 7,209 | 637 | 7,846 | ||||||||
Future income tax expenses | 4,146 | 2,423 | 6,569 | ||||||||
Future net cash flows | 10,464 | 3,503 | 13,967 | ||||||||
10% annual discount for estimated timing of cash flows | 3,372 | 910 | 4,282 | ||||||||
Standardized measure of discounted future net cash flows | $ | 7,092 | $ | 2,593 | $ | 9,685 | |||||
December 31, 2014 | |||||||||||
Future cash inflows | $ | 114,384 | $ | 23,795 | $ | 138,179 | |||||
Future production costs | 36,390 | 6,061 | 42,451 | ||||||||
Future development costs | 14,794 | 1,356 | 16,150 | ||||||||
Future income tax expenses | 21,813 | 6,968 | 28,781 | ||||||||
Future net cash flows | 41,387 | 9,410 | 50,797 | ||||||||
10% annual discount for estimated timing of cash flows | 17,239 | 2,898 | 20,137 | ||||||||
Standardized measure of discounted future net cash flows | $ | 24,148 | $ | 6,512 | $ | 30,660 | |||||
December 31, 2013 | |||||||||||
Future cash inflows | $ | 102,765 | $ | 28,454 | $ | 131,219 | |||||
Future production costs | 33,271 | 6,819 | 40,090 | ||||||||
Future development costs | 12,285 | 1,501 | 13,786 | ||||||||
Future income tax expenses | 20,222 | 8,148 | 28,370 | ||||||||
Future net cash flows | 36,987 | 11,986 | 48,973 | ||||||||
10% annual discount for estimated timing of cash flows | 15,818 | 4,049 | 19,867 | ||||||||
Standardized measure of discounted future net cash flows | $ | 21,169 | $ | 7,937 | $ | 29,106 | |||||
153
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Changes in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
millions | United States | International | Total | ||||||||
2015 | |||||||||||
Balance at January 1 | $ | 24,148 | $ | 6,512 | $ | 30,660 | |||||
Sales and transfers of oil and gas produced, net of production costs | (4,079 | ) | (1,153 | ) | (5,232 | ) | |||||
Net changes in prices and production costs | (28,967 | ) | (8,010 | ) | (36,977 | ) | |||||
Changes in estimated future development costs | 4,408 | 221 | 4,629 | ||||||||
Extensions, discoveries, additions, and improved recovery, less related costs | 219 | — | 219 | ||||||||
Development costs incurred during the period | 2,311 | 379 | 2,690 | ||||||||
Revisions of previous quantity estimates | (1,890 | ) | 47 | (1,843 | ) | ||||||
Purchases of minerals in place | 30 | — | 30 | ||||||||
Sales of minerals in place | (2,262 | ) | — | (2,262 | ) | ||||||
Accretion of discount | 3,648 | 1,143 | 4,791 | ||||||||
Net change in income taxes | 9,940 | 3,193 | 13,133 | ||||||||
Other | (414 | ) | 261 | (153 | ) | ||||||
Balance at December 31 | $ | 7,092 | $ | 2,593 | $ | 9,685 | |||||
2014 | |||||||||||
Balance at January 1 | $ | 21,169 | $ | 7,937 | $ | 29,106 | |||||
Sales and transfers of oil and gas produced, net of production costs | (8,780 | ) | (2,492 | ) | (11,272 | ) | |||||
Net changes in prices and production costs | (3,981 | ) | (1,984 | ) | (5,965 | ) | |||||
Changes in estimated future development costs | (4,180 | ) | (250 | ) | (4,430 | ) | |||||
Extensions, discoveries, additions, and improved recovery, less related costs | 963 | — | 963 | ||||||||
Development costs incurred during the period | 2,591 | 279 | 2,870 | ||||||||
Revisions of previous quantity estimates | 13,703 | 1,921 | 15,624 | ||||||||
Purchases of minerals in place | — | — | — | ||||||||
Sales of minerals in place | (591 | ) | (696 | ) | (1,287 | ) | |||||
Accretion of discount | 3,221 | 1,341 | 4,562 | ||||||||
Net change in income taxes | (1,294 | ) | 549 | (745 | ) | ||||||
Other | 1,327 | (93 | ) | 1,234 | |||||||
Balance at December 31 | $ | 24,148 | $ | 6,512 | $ | 30,660 | |||||
154
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Changes in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves (Continued)
millions | United States | International | Total | ||||||||
2013 | |||||||||||
Balance at January 1 | $ | 17,538 | $ | 8,776 | $ | 26,314 | |||||
Sales and transfers of oil and gas produced, net of production costs | (7,517 | ) | (2,881 | ) | (10,398 | ) | |||||
Net changes in prices and production costs | 1,433 | (1,072 | ) | 361 | |||||||
Changes in estimated future development costs | (2,326 | ) | (193 | ) | (2,519 | ) | |||||
Extensions, discoveries, additions, and improved recovery, less related costs | 2,659 | (128 | ) | 2,531 | |||||||
Development costs incurred during the period | 1,076 | 193 | 1,269 | ||||||||
Revisions of previous quantity estimates | 6,526 | 1,324 | 7,850 | ||||||||
Purchases of minerals in place | 253 | — | 253 | ||||||||
Sales of minerals in place | 284 | — | 284 | ||||||||
Accretion of discount | 2,671 | 1,465 | 4,136 | ||||||||
Net change in income taxes | (1,865 | ) | 401 | (1,464 | ) | ||||||
Other | 437 | 52 | 489 | ||||||||
Balance at December 31 | $ | 21,169 | $ | 7,937 | $ | 29,106 | |||||
155
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data
The following summarizes quarterly financial data for 2015 and 2014:
millions except per-share amounts | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||
2015 | |||||||||||||||
Sales revenues | $ | 2,585 | $ | 2,637 | $ | 2,230 | $ | 2,034 | |||||||
Gains (losses) on divestitures and other, net | (264 | ) | (1 | ) | (542 | ) | 19 | ||||||||
Impairments | 2,783 | 30 | 758 | 1,504 | |||||||||||
Operating income (loss) | (4,208 | ) | 90 | (2,549 | ) | (2,142 | ) | ||||||||
Net income (loss) | (3,236 | ) | 108 | (2,160 | ) | (1,524 | ) | ||||||||
Net income (loss) attributable to noncontrolling interests | 32 | 47 | 75 | (274 | ) | ||||||||||
Net income (loss) attributable to common stockholders | (3,268 | ) | 61 | (2,235 | ) | (1,250 | ) | ||||||||
Earnings per share | |||||||||||||||
Net income (loss) attributable to common stockholders—basic | $ | (6.45 | ) | $ | 0.12 | $ | (4.41 | ) | $ | (2.45 | ) | ||||
Net income (loss) attributable to common stockholders—diluted | $ | (6.45 | ) | $ | 0.12 | $ | (4.41 | ) | $ | (2.45 | ) | ||||
Average number common shares outstanding—basic | 507 | 508 | 508 | 508 | |||||||||||
Average number common shares outstanding—diluted | 507 | 509 | 508 | 508 | |||||||||||
2014 | |||||||||||||||
Sales revenues | $ | 4,338 | $ | 4,385 | $ | 4,230 | $ | 3,422 | |||||||
Gains (losses) on divestitures and other, net | 1,506 | 54 | 780 | (245 | ) | ||||||||||
Impairments | 3 | 117 | 394 | 322 | |||||||||||
Operating income (loss) | 2,975 | 1,209 | 1,698 | (479 | ) | ||||||||||
Tronox-related contingent loss | 4,300 | 19 | 19 | 22 | |||||||||||
Net income (loss) | (2,626 | ) | 266 | 1,147 | (350 | ) | |||||||||
Net income (loss) attributable to noncontrolling interests | 43 | 39 | 60 | 45 | |||||||||||
Net income (loss) attributable to common stockholders | (2,669 | ) | 227 | 1,087 | (395 | ) | |||||||||
Earnings per share | |||||||||||||||
Net income (loss) attributable to common stockholders—basic | $ | (5.30 | ) | $ | 0.45 | $ | 2.13 | $ | (0.78 | ) | |||||
Net income (loss) attributable to common stockholders—diluted | $ | (5.30 | ) | $ | 0.45 | $ | 2.12 | $ | (0.78 | ) | |||||
Average number common shares outstanding—basic | 504 | 505 | 506 | 507 | |||||||||||
Average number common shares outstanding—diluted | 504 | 507 | 508 | 507 | |||||||||||
156
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
EVALUATION AND DISCLOSURE CONTROLS AND PROCEDURES
Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2015.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
See Management’s Assessment of Internal Control Over Financial Reporting under Item 8 of this Form 10-K.
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
See Report of Independent Registered Public Accounting Firm under Item 8 of this Form 10-K.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes in Anadarko’s internal control over financial reporting during the fourth quarter of 2015 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. See Management’s Assessment of Internal Control Over Financial Reporting under Item 8 of this Form 10-K.
Item 9B. Other Information
None.
157
PART III
Item 10. Directors, Executive Officers, and Corporate Governance
See Anadarko Board of Directors, Corporate Governance—Committees of the Board, Corporate Governance—Board of Directors, and Section 16(a) Beneficial Ownership Reporting Compliance in the Definitive Proxy Statement (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), each of which is incorporated herein by reference.
See list of Executive Officers of the Registrant under Items 1 and 2 of this Form 10-K, which is incorporated herein by reference.
The Company’s Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (Code of Ethics) can be found on the Company’s website located at www.anadarko.com/Responsibility/Good-Governance. Any stockholder may request a printed copy of the Code of Ethics by submitting a written request to the Company’s Corporate Secretary. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its website. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.
Item 11. Executive Compensation
See Corporate Governance—Board of Directors—Compensation and Benefits Committee Interlocks and Insider Participation, Corporate Governance—Board of Directors—Director Compensation, Corporate Governance—Director Compensation Table for 2015, Compensation and Benefits Committee Report on 2015 Executive Compensation, Compensation Discussion and Analysis, and Executive Compensation in the Proxy Statement, each of which is incorporated herein by reference. The Compensation and Benefits Committee Report and related information incorporated by reference herein shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such 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.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
See Security Ownership of Certain Beneficial Owners and Management in the Proxy Statement and Securities Authorized for Issuance under Equity Compensation Plans under Item 5 of this Form 10-K, each of which is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
See Corporate Governance—Board of Directors and Transactions with Related Persons in the Proxy Statement, each of which is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
See Independent Auditor in the Proxy Statement, which is incorporated herein by reference.
158
PART IV
Item 15. Exhibits, Financial Statement Schedules
a) EXHIBITS
The following documents are filed as part of this Form 10-K or incorporated by reference:
(1) | The Consolidated Financial Statements of Anadarko Petroleum Corporation are listed on the Index to this Form 10-K, page 82. |
(2) | Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith or double asterisk (**) and are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing under File Number 1-8968 as indicated. |
Exhibit Number | Description | |||
2 | (i) | Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Acquisition Sub, Inc. and Kerr-McGee Corporation, filed as Exhibit 2.2 to Form 8-K filed on June 26, 2006 | ||
3 | (i) | Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 3.3 to Form 8-K filed on May 22, 2009 | ||
(ii) | By-Laws of Anadarko Petroleum Corporation, amended and restated as of September 15, 2015, filed as Exhibit 3.1 to Form 8-K filed on September 21, 2015 | |||
4 | (i) | Trustee Indenture, dated as of September 19, 2006, Anadarko Petroleum Corporation to The Bank of New York Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on September 19, 2006 | ||
(ii) | Third Supplemental Indenture, dated as of June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.2 to Form 8-K filed on June 10, 2015 | |||
(iii) | Second Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A., filed as Exhibit 4.1 to Form 8-K filed on October 6, 2006 | |||
(iv) | Ninth Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A., filed as Exhibit 4.2 to Form 8-K filed on October 6, 2006 | |||
(v) | Officers’ Certificate of Anadarko Petroleum Corporation, dated March 2, 2009, establishing the 7.625% Senior Notes due 2014 and the 8.700% Senior Notes due 2019, filed as Exhibit 4.1 to Form 8-K filed on March 6, 2009 | |||
(vi) | Form of 7.625% Senior Notes due 2014, filed as Exhibit 4.2 to Form 8-K filed on March 6, 2009 | |||
(vii) | Form of 8.700% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on March 6, 2009 | |||
(viii) | Officers’ Certificate of Anadarko Petroleum Corporation, dated June 9, 2009, establishing the 5.75% Senior Notes due 2014, the 6.95% Senior Notes due 2019 and the 7.95% Senior Notes due 2039, filed as Exhibit 4.1 to Form 8-K filed on June 12, 2009 | |||
(ix) | Form of 5.75% Senior Notes due 2014, filed as Exhibit 4.2 to Form 8-K filed on June 12, 2009 | |||
(x) | Form of 6.95% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on June 12, 2009 | |||
(xi) | Form of 7.95% Senior Notes due 2039, filed as Exhibit 4.4 to Form 8-K filed on June 12, 2009 | |||
(xii) | Officers’ Certificate of Anadarko Petroleum Corporation dated March 9, 2010, establishing the 6.200% Senior Notes due 2040, filed as Exhibit 4.1 to Form 8-K filed on March 16, 2010 | |||
159
Exhibit Number | Description | |||
4 | (xiii) | Form of 6.200% Senior Notes due 2040, filed as Exhibit 4.2 to Form 8-K filed on March 16, 2010 | ||
(xiv) | Officers’ Certificate of Anadarko Petroleum Corporation dated August 9, 2010, establishing the 6.375% Senior Notes due 2017, filed as Exhibit 4.1 to Form 8-K filed on August 12, 2010 | |||
(xv) | Form of 6.375% Senior Notes due 2017, filed as Exhibit 4.2 to Form 8-K filed on August 12, 2010 | |||
(xvi) | Officers’ Certificate of Anadarko Petroleum Corporation dated July 7, 2014, establishing the 3.45% Senior Notes due 2024 and the 4.50% Senior Notes due 2044, filed as Exhibit 4.1 to Form 8-K filed on July 7, 2014 | |||
(xvii) | Form of 3.45% Senior Notes due 2024, filed as Exhibit 4.2 to Form 8-K filed on July 7, 2014 | |||
(xviii) | Form of 4.50% Senior Notes due 2044, filed as Exhibit 4.3 to Form 8-K filed on July 7, 2014 | |||
(xix) | Purchase Contract Agreement, dated June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on June 10, 2015 | |||
(xx) | Form of Unit (included in Exhibit 4.xix) | |||
(xxi) | Form of Purchase Contract (included in Exhibit 4.xix) | |||
(xxii) | Form of Amortizing Note (included in Exhibit 4.ii) | |||
† | 10 | (i) | 1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998, filed as Appendix A to DEF 14A filed on March 16, 1998 | |
† | (ii) | Form of Anadarko Petroleum Corporation 1998 Director Stock Plan Stock Option Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 17, 2005 | ||
† | (iii) | Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan, filed as Appendix A to DEF 14A filed on March 18, 2005 | ||
† | (iv) | Form of Anadarko Petroleum Corporation Executive 1999 Stock Incentive Plan Stock Option Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 17, 2005 | ||
† | (v) | Form of Anadarko Petroleum Corporation Non-Executive 1999 Stock Incentive Plan Stock Option Agreement, filed as Exhibit 10.3 to Form 8-K filed on November 17, 2005 | ||
† | (vi) | Form of Stock Option Agreement—1999 Stock Incentive Plan (UK Nationals), filed as Exhibit 10.4 to Form 8-K filed on November 17, 2005 | ||
† | (vii) | Amendment to Stock Option Agreement Under the Anadarko Petroleum Corporation 1999 Stock Incentive Plan, filed as Exhibit 10.1 to Form 8-K filed on January 23, 2007 | ||
† | (viii) | Anadarko Petroleum Corporation 1999 Stock Incentive Plan (Amendment to Performance Unit Agreement), filed as Exhibit 10.3 to Form 8-K filed on November 13, 2007 | ||
† | (ix) | Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Agreement, filed as Exhibit 10(b)(xxiv) to Form 10-K for year ended December 31, 1999, filed on March 16, 2000 | ||
† | (x) | Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Unit Award Letter, filed as Exhibit 10.1 to Form 8-K filed on November 13, 2007 | ||
† | (xi) | The Approved UK Sub-Plan of the Anadarko Petroleum Corporation 1999 Stock Incentive Plan, filed as Exhibit 10(b)(xxiv) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004 | ||
† | (xii) | Key Employee Change of Control Contract, filed as Exhibit 10(b)(xxii) to Form 10-K for year ended December 31, 1997, filed on March 18, 1998 | ||
† | (xiii) | First Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract, filed as Exhibit 10(b) to Form 10-Q for quarter ended September 30, 2000, filed on November 13, 2000 | ||
160
Exhibit Number | Description | |||
† | 10 | (xiv) | Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract, filed as Exhibit 10(b)(ii) to Form 10-Q for quarter ended June 30, 2003, filed on August 11, 2003 | |
† | (xv) | Form of Key Employee Change of Control Contract (2011), filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2011, filed on July 27, 2011 | ||
† | (xvi) | Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract (Applicable to Vice Presidents Other Than Executive Officers as of October 2013), filed as Exhibit 10(ii) to Form 10-Q for the quarter ended March 31, 2015, filed on May 4, 2015 | ||
† | (xvii) | Letter Agreement regarding Post-Retirement Benefits, dated February 16, 2004—Robert J. Allison, Jr., filed as Exhibit 10(b)(xxxiv) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004 | ||
† | (xviii) | Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xxii) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010 | ||
† | (xix) | First Amendment, dated July 1, 2010, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xviii) to Form 10-K for the year ended December 31, 2014, filed on February 20, 2015 | ||
† | (xx) | Second Amendment, dated November 30, 2011, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xix) to Form 10-K for the year ended December 31, 2014, filed on February 20, 2015 | ||
† | (xxi) | Third Amendment, dated December 18, 2014, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xx) to Form 10-K for the year ended December 31, 2014, filed on February 20, 2015 | ||
† | (xxii) | Anadarko Retirement Restoration Plan (As Amended and Restated Effective as of November 7, 2007), filed as Exhibit 10.2 to Form 8-K filed on November 13, 2007 | ||
† | (xxiii) | First Amendment, dated November 30, 2011, to the Anadarko Retirement Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xxii) to Form 10-K for the year ended December 31, 2014, filed on February 20, 2015 | ||
† | (xxiv) | Anadarko Petroleum Corporation Estate Enhancement Program, filed as Exhibit 10(b)(xxxiv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999 | ||
† | (xxv) | Estate Enhancement Program Agreement between Anadarko Petroleum Corporation and Eligible Executives, filed as Exhibit 10(b)(xxxv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999 | ||
† | (xxvi) | Estate Enhancement Program Agreements effective November 29, 2000, filed as Exhibit 10(b)(xxxxii) to Form 10-K for year ended December 31, 2000, filed on March 15, 2001 | ||
† | (xxvii) | Anadarko Petroleum Corporation Management Life Insurance Plan, restated November 1, 2002, filed as Exhibit 10(b)(xxxii) to Form 10-K for year ended December 31, 2002, filed on March 14, 2003 | ||
† | (xxviii) | First Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective June 30, 2003, filed as Exhibit 10(b)(xliii) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004 | ||
† | (xxix) | Second Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective January 1, 2008, filed as Exhibit 10(xxix) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010 | ||
† | (xxx) | Anadarko Petroleum Corporation Officer Severance Plan, filed as Exhibit 10(b)(iv) to Form 10-Q for quarter ended September 30, 2003, filed on November 12, 2003 | ||
† | (xxxi) | Form of Termination Agreement and Release of All Claims Under Officer Severance Plan, filed as Exhibit 10(b)(v) to Form 10-Q for quarter ended September 30, 2003, filed on November 12, 2003 | ||
161
Exhibit Number | Description | |||
† | 10 | (xxxii) | Form of Director and Officer Indemnification Agreement, filed as Exhibit 10 to Form 8-K filed on September 3, 2004 | |
(xxxiii) | $5,000,000,000 Revolving Credit Agreement, dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., DnB NorBank ASA, The Royal Bank of Scotland plc, Société Générale, and Wells Fargo Bank, N.A., as Syndication Agents, and the several lenders named therein, filed as Exhibit 10.1 to Form 8-K filed on September 8, 2010 | |||
(xxxiv) | First Amendment to Revolving Credit Agreement, dated as of August 3, 2011, to the Revolving Credit Agreement dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A. as Administrative Agent, Bank of America, N.A., DnB Nor Bank ASA, The Royal Bank of Scotland plc, Société Générale, and Wells Fargo Bank, N.A., as co-syndication agents, and each of the Lenders from time to time party thereto, filed as Exhibit 10(i) to Form 10-Q for quarter ended September 30, 2011, filed on October 31, 2011 | |||
(xxxv) | Second Amendment to Revolving Credit Agreement, dated as of March 26, 2014, to the Revolving Credit Agreement dated as of September 2, 2010, as amended on August 3, 2011, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., DnB Nor Bank ASA, The Royal Bank of Scotland plc, Société Générale, and Wells Fargo Bank, N.A., as co-syndication agents, and each of the Lenders from time to time party thereto, filed as Exhibit 10(ii) to Form 10-Q for quarter ended March 31, 2014, filed on May 5, 2014 | |||
† | (xxxvi) | Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan, effective as of May 20, 2008, filed as Exhibit 10.1 to Form 8-K filed on May 27, 2008 | ||
† | (xxxvii) | Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Stock Option Award Agreement, filed as Exhibit 10.3 to Form 8-K filed on November 13, 2009 | ||
† | (xxxviii) | Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 13, 2009 | ||
† | (xxxvix) | Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 13, 2009 | ||
† | (xl) | Anadarko Petroleum Corporation 2008 Director Compensation Plan, effective as of May 20, 2008, filed as Exhibit 10.2 to Form 8-K filed on May 27, 2008 | ||
†* | (xli) | First Amendment to Anadarko Petroleum Corporation 2008 Director Compensation Plan, dated February 8, 2016 | ||
† | (xlii) | Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan, filed as Exhibit 10.3 to Form 8-K filed on May 27, 2008 | ||
† | (xliii) | Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan (2013), filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2013, filed on July 29, 2013 | ||
†* | (xliv) | Terms and Conditions of Elective Deferred Share Awards for Anadarko Petroleum Corporation 2008 Director Compensation Plan | ||
† | (xlv) | Anadarko Petroleum Corporation Benefits Trust Agreement, amended and restated effective as of November 5, 2008, filed as Exhibit 10(lvi) to Form 10-K for year ended December 31, 2008, filed on February 25, 2009 | ||
† | (xlvi) | Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2012), filed as Exhibit 10(i) to Form 10-Q for the quarter ended June 30, 2014, filed on July 29, 2014 | ||
† | (xlvii) | First Amendment, dated December 17, 2013, to the Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2012), filed as Exhibit 10(ii) to Form 10-Q for the quarter ended June 30, 2014, filed on July 29, 2014 | ||
162
Exhibit Number | Description | |||
10 | (xlviii) | Operating Agreement, dated October 1, 2009, between BP Exploration & Production Inc., as Operator, and MOEX Offshore 2007 LLC, as Non-Operator, as ratified by that certain Ratification and Joinder of Operating Agreement, dated December 17, 2009, by and among BP Exploration & Production Inc., Anadarko Petroleum Corporation (as Non-Operator), Anadarko E&P Company LP (as predecessor in interest to Anadarko Petroleum Corporation), and MOEX Offshore 2007 LLC, together with material exhibits, filed as Exhibit 10 to Form 10-Q for quarter ended June 30, 2010, filed on August 3, 2010 | ||
(xlix) | Confidential Settlement Agreement, Mutual Releases and Agreement to Indemnify, dated October 16, 2011, by and among BP Exploration & Production Inc., Anadarko Petroleum Corporation, Anadarko E&P Company LP, BP Corporation North America Inc. and BP p.l.c., filed as Exhibit 10(xlii) to Form 10-K for year ended December 31, 2011, filed on February 21, 2012 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment) | |||
† | (l) | Severance Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated February 16, 2012, filed as Exhibit 10.2 to Form 8-K filed on February 21, 2012 | ||
† | (li) | Time Sharing Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated May 15, 2012, filed as Exhibit 10(ii) to Form 10-Q for quarter ended June 30, 2012, filed on August 8, 2012 | ||
† | (lii) | First Amendment to Time Sharing Agreement between R.A. Walker and Anadarko Petroleum Corporation, dated June 2, 2015, filed as Exhibit 10(ii) to Form 10-Q for the quarter ended June 30, 2015, filed on July 28, 2015 | ||
† | (liii) | Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, effective as of May 15, 2012, filed as Exhibit 10.1 to Form 8-K filed on May 15, 2012 | ||
† | (liv) | Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Stock Option Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on May 15, 2012 | ||
† | (lv) | Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.3 to Form 8-K filed on May 15, 2012 | ||
† | (lvi) | Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.4 to Form 8-K filed on May 15, 2012 | ||
† | (lvii) | Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 9, 2012 | ||
† | (lviii) | Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 9, 2012 | ||
† | (lix) | Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement (2014), filed as Exhibit 10.1 to Form 8-K filed on November 10, 2014 | ||
† | (lx) | Form of U.K. Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan, filed as Exhibit 10.5 to Form 8-K filed on May 15, 2012 | ||
† | (lxi) | Amended and Restated Performance Unit Award Agreement, effective November 5, 2012, for R. A. Walker, filed as Exhibit 10.3 to Form 8-K filed on November 9, 2012 | ||
(lxii) | Settlement Agreement dated as of April 3, 2014, by and among (1) the Anadarko Litigation Trust, (2) the United States of America in its capacity as plaintiff-intervenor in the Tronox Adversary Proceeding and acting for and on behalf of certain U.S. government agencies and (3) Anadarko Petroleum Corporation, Kerr-McGee Corporation, and certain other subsidiaries, filed as exhibit 10.1 to Form 8-K filed on April 3, 2014 | |||
163
Exhibit Number | Description | |||
10 | (lxiii) | Credit Agreement, dated as of June 17, 2014, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., Citibank, N.A., The Royal Bank of Scotland plc, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on June 23, 2014 | ||
(lxiv) | First Amendment to Credit Agreement, dated November 14, 2014, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on November 19, 2014 | |||
(lxv) | Amendment and Maturity Extension Agreement, dated December 14, 2015, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on December 18, 2015 | |||
(lxvi) | 364-Day Revolving Credit Agreement, dated as of June 17, 2014, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., Citibank, N.A., The Royal Bank of Scotland plc, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.2 to Form 8-K filed on June 23, 2014 | |||
(lxvii) | First Amendment to 364-Day Revolving Credit Agreement, dated November 14, 2014, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as Exhibit 10.2 to Form 8-K filed on November 19, 2014 | |||
(lxviii) | Form of Commercial Paper Dealer Agreement for Commercial Paper Program, filed as Exhibit 10.1 to Form 8-K filed on January 21, 2015 | |||
† | (lxix) | Anadarko Petroleum Corporation Key Employee Change of Control Contract, dated June 1, 2015, for Christopher O. Champion, filed as Exhibit 10(i) to Form 10-Q for the quarter ended June 30, 2015, filed on July 28, 2015 | ||
(lxx) | 364-Day Revolving Credit Agreement, dated as of January 19, 2016, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd., Citibank, N.A., and Mizuho Bank, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on January 25, 2016 | |||
* | 12 | Computation of Ratios of Earnings to Fixed Charges | ||
* | 21 | List of Subsidiaries | ||
* | 23 | (i) | Consent of KPMG LLP | |
* | 23 | (ii) | Consent of Miller and Lents, Ltd. | |
* | 24 | Power of Attorney | ||
* | 31 | (i) | Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer | |
* | 31 | (ii) | Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer | |
** | 32 | Section 1350 Certifications | ||
* | 99 | Report of Miller and Lents, Ltd. | ||
* | 101 | .INS | XBRL Instance Document | |
* | 101 | .SCH | XBRL Schema Document | |
* | 101 | .CAL | XBRL Calculation Linkbase Document | |
* | 101 | .DEF | XBRL Definition Linkbase Document | |
* | 101 | .LAB | XBRL Label Linkbase Document | |
* | 101 | .PRE | XBRL Presentation Linkbase Document | |
_________________________________________________________________
† | Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15. |
164
The total amount of securities of the registrant authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrants and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the SEC, to furnish copies of any or all of such instruments to the SEC.
b) FINANCIAL STATEMENT SCHEDULES
Financial statement schedules have been omitted because they are not required, not applicable, or the information is included in the Company’s Consolidated Financial Statements.
165
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ANADARKO PETROLEUM CORPORATION | |||
February 17, 2016 | By: | /s/ ROBERT G. GWIN | |
Robert G. Gwin Executive Vice President, Finance and Chief Financial Officer | |||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 17, 2016.
Name and Signature | Title | |
(i) Principal executive officer and director: | ||
/s/ R. A. WALKER | Chairman, President and Chief Executive Officer | |
R. A. Walker | ||
(ii) Principal financial officer: | ||
/s/ ROBERT G. GWIN | Executive Vice President, Finance and Chief Financial Officer | |
Robert G. Gwin | ||
(iii) Principal accounting officer: | ||
/s/ CHRISTOPHER O. CHAMPION | Vice President, Chief Accounting Officer and Controller | |
Christopher O. Champion | ||
(iv) Directors:* | ||
ANTHONY R. CHASE KEVIN P. CHILTON H. PAULETT EBERHART PETER J. FLUOR RICHARD L. GEORGE JOSEPH W. GORDER JOHN R. GORDON SEAN GOURLEY MARK C. MCKINLEY ERIC D. MULLINS | ||
* Signed on behalf of each of these persons and on his own behalf: | ||
By: | /s/ ROBERT G. GWIN | |
Robert G. Gwin, Attorney-in-Fact | ||
166