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 |
| |
| – | other adverse weather conditions shortages
|
| |
| – | lack of availability or delays in the delivery of technology, equipment, or resources for operations |
Certain of our future drilling activities may not be successful and, if unsuccessful, could result in a material 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 a portion of our capital budget is devoted to higher-risk exploratory projects, it is likely that we will continue to experience significant exploration and dry hole expenses.
|
| | |
| RISK FACTORS
Certain of our future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Because of the percentage of our capital budget devoted to high-risk exploratory projects, it is likely that we will continue to experience significant exploration and dry hole expenses.
| |
We have limited influence over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. We have limited ability to influence the operation or future development of these nonoperated properties or the amount 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, adversely affect the timing of activities, or lead to unexpected future costs, including costs associated with the hazards and 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.
Our ability to sell and deliver our oil, natural-gas, and NGL production could be materially harmed if adequate gathering, processing, compression, transportation, and disposal facilities and equipment are unavailable.
The marketability of our production depends in part on the availability, proximity, and capacity of gathering, processing, compression, transportation, tankers, pipeline, and produced water facilities. These facilities may be temporarily unavailable to us due to market conditions, regulatory reasons, mechanical reasons or other factors or conditions. 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 natural-gas. In addition, in certain newer plays, the capacity of gathering, processing, compression, transportation, and disposal facilities and equipment may not be sufficient to accommodate potential production from existing and new wells. Construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new gathering, processing, compression, transportation, and disposal facilities and equipment, and we may experience delays or increased costs in accessing the pipelines, gathering systems or rail systems necessary to transport our production to points of sale or delivery or disposing of produced water.
Any significant change in market or other conditions affecting gathering, processing, compression, transportation, or disposal facilities and equipment or the availability of these facilities, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.
Our results of operations could be adversely affected by goodwill impairments.
As a result of mergers and acquisitions, we had approximately $4.8 billion of goodwill on our Consolidated Balance Sheet at December 31, 2018. 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 reported earnings.
|
| | |
| RISK FACTORS
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.
| |
Risks related to acquisitions and divestitures may adversely affect our business, financial condition, and results of operations.
Any acquisition involves potential risks, including, among other things:
We may reduce | |
| – | the validity of our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses, and costs |
| |
| – | the assumption of environmental, decommissioning, and other liabilities, and losses or ceasecosts for which we are not indemnified or for which our indemnity is inadequate |
| |
| – | a failure to pay dividends on our common stock.attain or maintain compliance with environmental, safety, and other governmental regulations |
In addition, from time to time, we may sell or otherwise dispose of certain of our properties as a result of an evaluation of our asset portfolio and to help enhance our liquidity. These transactions also have inherent risks, including:
| |
| – | possible delays in closing |
| |
| – | lower-than-expected sales proceeds for the disposed assets |
| |
| – | potential post-closing claims for indemnification |
Moreover, the agreements relating to these transactions contain provisions pursuant to which liabilities related to past and future operations, such as matters of litigation, environmental contingencies, royalty obligations and income taxes, have been allocated between the parties by means of liability assumptions, indemnities, escrows, trusts and similar arrangements. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. In addition, one or more of the parties in these transactions could fail to perform its obligations under the agreements as a result of financial distress. In the event that any such counterparty were to become the subject of a case proceeding under Title 11 of the U.S. Bankruptcy Code or any other insolvency law or similar law, the counterparty may not perform its obligations under the agreement and we may be responsible for the cost of the obligations assumed by the counterparties. As a result, after a divestiture, the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
If any of these risks materialize, the benefits of such acquisition or divestiture may not be fully realized, if at all, and our business, financial condition, and results of operations could be negatively impacted.
|
| | |
| RISK FACTORS
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.
| |
Our business could be negatively affected by security threats, including cyber threats, and other disruptions.
As an oil and gas producer, we face various security threats, including cyber threats such as attempts to gain unauthorized access to, or control of, sensitive information or to render data or systems corrupted or 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. In addition, our business has become increasingly dependent on digital technologies and we anticipate expanding our use of technology in our operations, including through data analytics and process automation. Further, we have exposure to cyber incidents and the negative impacts of such incidents related to our critical data and proprietary information housed on third-party information technology systems, including the cloud. Our vendors and other business partners may also separately suffer disruptions or breaches from cyber attacks which could adversely impact our operations and compromise our information. We continuously work to install new, and upgrade existing, information technology systems and provide employee awareness training on phishing, malware, and other cyber risks to help ensure that we are protected, to the extent possible, against cyber risks and security breaches. We also perform periodic drills for responding to cyber incidences. There can be no assurance that such safeguards, procedures, and controls will be sufficient to prevent security breaches from occurring. Cyber attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to, or control of our data, systems, or facilities, 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 or systems, which could have an adverse effect on our reputation, financial condition, results of operations, or cash flows.
While we have experienced cyber 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. We could incur substantial remediation and other costs or suffer other negative consequences, including litigation risks. In addition, as cyber 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 cyber vulnerabilities.
Provisions in our corporate documents and Delaware law could delay or prevent a change of control of Anadarko, even if that change would be beneficial to our stockholders.
Our restated certificate of incorporation and by-laws contain provisions that may make a change of control of Anadarko difficult, even if it may be beneficial to our stockholders, including provisions governing the nomination and removal of directors, the prohibition of stockholder action by written consent and regulation of stockholders’ ability to bring matters for action before annual stockholder meetings, and the authorization given to our Board of Directors to issue and set the terms of preferred stock.
In addition, Section 203 of the Delaware General Corporation Law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.
We may reduce or cease to pay dividends on our common stock.
We can provide no assurance that we will continue to pay dividends at the current rate or at all. As of February 2019, our quarterly dividend was $0.30 per share. 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.
Difficulty attracting and retaining experienced technical personnel could reduce our competitiveness and prospects for future success.
Our exploratory drilling success and the success of other development and operating activities depends, 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.
PART II
| |
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
| | |
| MARKETOTHER 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.
| |
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 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.
In September 2018, Anadarko E&P Onshore LLC, a subsidiary of the Company, entered into a final consent assessment with the Pennsylvania Department of Environmental Protection resolving issues concerning enforcement over a produced water release in Pennsylvania in 2015 and agreed to pay a penalty of $350,000.
Kerr-McGee Oil and Gas Onshore, LP, a subsidiary of the Company, is currently in negotiations with the State of Colorado’s Department of Public Health and Environment with respect to alleged noncompliance with the Colorado Air Quality Control Commission’s Regulations. 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.
Kerr-McGee Gathering, LLC, a subsidiary of the Company, is currently in negotiations with the EPA and the Department of Justice with respect to alleged noncompliance with the leak detection and repair requirements of the Clean Air Act at its Fort Lupton complex in Colorado. 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 18—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.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
| MARKET INFORMATION, HOLDERS, AND DIVIDENDS |
At January 31, 2019, there were approximately 9,074 holders of record of Anadarko common stock. The common stock of Anadarko is traded on the New York Stock Exchange under the symbol “APC”.
The amount of future dividends paid to Anadarko common stockholders is determined by the Board on a quarterly basis and is based on the Company’s earnings, financial condition, 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. In November 2018, the Company announced an increase in the quarterly dividend to $0.30 from $0.25 per share of common stock. 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.
|
|
| 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, 2018:
|
| | | | | | | | |
| Plan Category | (a) Number of securities to be issued upon exercise of outstanding options, warrants, and rights |
| (b) Weighted-average exercise price of outstanding options, warrants, and rights | | (c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column(a)) |
|
| Equity compensation plans approved by security holders | 6,356,970 |
| | $ | 67.00 |
| 20,246,444 |
|
| Equity compensation plans not approved by security holders | — |
| | — |
| — |
|
| Total | 6,356,970 |
| | $ | 67.00 |
| 20,246,444 |
|
|
| | | | | | | | | | |
| 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 2018:
|
| | | | | | | | | | | | |
| 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(2) |
| Approximate dollar value of shares that may yet be purchased under the plans or programs (2)(3) | |
| October 1-31, 2018 | 35,626 |
| | $ | 64.55 |
| — |
| | $ | 500,000,003 |
|
| November 1-30, 2018 | 56,912 |
| | $ | 55.73 |
| — |
| | $ | 1,500,000,003 |
|
| December 1-31, 2018 | 4,792,707 |
| | $ | 52.35 |
| 4,776,318 |
| | $ | 1,250,000,064 |
|
| Total | 4,885,245 |
| | $ | 52.48 |
| 4,776,318 |
| |
|
|
| |
(1) | 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.
|
2018, 109 thousand shares were repurchased related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans. For additional information, see Note 19—23—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
| |
(2) | During the fourth quarter of 2018, under the Share Repurchase Program, the Company repurchased 4.8 million shares of common stock in the open market for $250 million. For additional information, see Note 21—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
| |
(3) | The Company announced a $2.5 billion Share-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018 and $4.0 billion in July 2018. In November 2018, the program was further expanded to $5.0 billion and extended through June 30, 2020. For additional information, see Note 21—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
APC 2018 FORM 10-K | 53
The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall the 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; Chesapeake Energy 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,Copyright© 2019 Standard & Poor's, a division of The McGraw-Hill Companies Inc.S&P Global. 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, 2010,2013, and its relative performance is tracked through December 31, 2015.2018.
| | | Fiscal Year Ended December 31 | 2010 | | 2011 | | 2012 | | 2013 | | 2014 | | 2015 | 2013 |
| | 2014 |
| | 2015 |
| | 2016 |
| | 2017 |
| | 2018 |
|
| Anadarko Petroleum Corporation | $ | 100.00 |
| | $ | 100.70 |
| | $ | 98.53 |
| | $ | 105.81 |
| | $ | 111.25 |
| | $ | 66.53 |
| $ | 100.00 |
| | $ | 105.14 |
| | $ | 62.88 |
| | $ | 90.58 |
| | $ | 69.96 |
| | $ | 58.19 |
|
| S&P 500 | 100.00 |
| | 102.11 |
| | 118.45 |
| | 156.82 |
| | 178.29 |
| | 180.75 |
| 100.00 |
| | 113.69 |
| | 115.26 |
| | 129.05 |
| | 157.22 |
| | 150.33 |
|
| Peer Group | 100.00 |
| | 105.57 |
| | 107.65 |
| | 135.30 |
| | 124.85 |
| | 95.82 |
| 100.00 |
| | 92.09 |
| | 69.98 |
| | 91.31 |
| | 94.42 |
| | 82.93 |
|
4854 | APC 2018 FORM 10-K
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 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Summary Financial Information (1) |
| millions except per-share and employee amounts | 2018 |
| | 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
|
Sales Revenues (6) | $ | 13,070 |
| | $ | 10,969 |
| | $ | 8,447 |
| | $ | 9,486 |
| | $ | 16,375 |
|
| Gains (Losses) on Divestitures and Other, net | 312 |
| | 939 |
| | (578 | ) | | (788 | ) | | 2,095 |
|
| Total Revenues and Other | 13,382 |
| | 11,908 |
| | 7,869 |
| | 8,698 |
| | 18,470 |
|
| Operating Income (Loss) | 2,619 |
| | (565 | ) | | (2,372 | ) | | (8,743 | ) | | 5,438 |
|
Net Income (Loss) (2) | 752 |
| | (211 | ) | | (2,808 | ) | | (6,812 | ) | | (1,563 | ) |
| Net Income (Loss) Attributable to Common Stockholders | 615 |
| | (456 | ) | | (3,071 | ) | | (6,692 | ) | | (1,750 | ) |
| Per Common Share (amounts attributable to common stockholders) | | | | | | | | | |
| Net Income (Loss)—Basic | $ | 1.20 |
| | $ | (0.85 | ) | | $ | (5.90 | ) | | $ | (13.18 | ) | | $ | (3.47 | ) |
| Net Income (Loss)—Diluted | $ | 1.20 |
| | $ | (0.85 | ) | | $ | (5.90 | ) | | $ | (13.18 | ) | | $ | (3.47 | ) |
| Dividends | $ | 1.05 |
| | $ | 0.20 |
| | $ | 0.20 |
| | $ | 1.08 |
| | $ | 0.99 |
|
| Average Number of Common Shares Outstanding—Basic | 504 |
| | 548 |
| | 522 |
| | 508 |
| | 506 |
|
| Average Number of Common Shares Outstanding—Diluted | 504 |
| | 548 |
| | 522 |
| | 508 |
| | 506 |
|
Net Cash Provided by (Used in) Operating Activities (3) | $ | 5,929 |
| | $ | 4,009 |
| | $ | 3,000 |
| | $ | (1,877 | ) | | $ | 8,466 |
|
| Net Cash Provided by (Used in) Investing Activities | (5,982 | ) | | (1,030 | ) | | (2,742 | ) | | (4,771 | ) | | (6,472 | ) |
| Net Cash Provided by (Used in) Financing Activities | (3,177 | ) | | (1,613 | ) | | 2,008 |
| | 220 |
| | 1,675 |
|
| Capital Expenditures | $ | 6,185 |
| | $ | 5,300 |
| | $ | 3,314 |
| | $ | 5,888 |
| | $ | 9,256 |
|
Long-term debt - Anadarko (4) | $ | 10,683 |
| | $ | 12,054 |
| | $ | 12,162 |
| | $ | 12,945 |
| | $ | 12,595 |
|
| Long-term debt - WES and WGP | 4,787 |
| | 3,493 |
| | 3,119 |
| | 2,691 |
| | 2,409 |
|
| Total Stockholders’ Equity | 8,496 |
| | 10,696 |
| | 12,212 |
| | 12,819 |
| | 19,725 |
|
| Total Assets | $ | 40,376 |
| | $ | 42,086 |
| | $ | 45,564 |
| | $ | 46,331 |
| | $ | 60,879 |
|
| Annual Sales Volume | | | | | | | | | |
| Oil (MMBbls) | 141 |
| | 129 |
| | 116 |
| | 116 |
| | 106 |
|
| Natural Gas (Bcf) | 390 |
| | 478 |
| | 766 |
| | 852 |
| | 945 |
|
| Natural-Gas Liquids (MMBbls) | 37 |
| | 36 |
| | 46 |
| | 47 |
| | 44 |
|
Total (MMBOE) (5) | 243 |
| | 245 |
| | 290 |
| | 305 |
| | 308 |
|
| Average Daily Sales Volume | | | | | | | | | |
| Oil (MBbls/d) | 385 |
| | 355 |
| | 316 |
| | 317 |
| | 292 |
|
| Natural Gas (MMcf/d) | 1,069 |
| | 1,309 |
| | 2,093 |
| | 2,334 |
| | 2,589 |
|
| Natural-Gas Liquids (MBbls/d) | 103 |
| | 99 |
| | 128 |
| | 130 |
| | 119 |
|
Total (MBOE/d) (5) | 666 |
| | 672 |
| | 793 |
| | 836 |
| | 843 |
|
| Proved Reserves | | | | | | | | | |
| Oil Reserves (MMBbls) | 667 |
| | 658 |
| | 702 |
| | 713 |
| | 929 |
|
| Natural-gas Reserves (Tcf) | 3.2 |
| | 3.2 |
| | 4.4 |
| | 6.0 |
| | 8.7 |
|
| Natural-gas Liquids Reserves (MMBbls) | 268 |
| | 243 |
| | 283 |
| | 340 |
| | 479 |
|
Total Proved Reserves (MMBOE) (5) | 1,473 |
| | 1,439 |
| | 1,722 |
| | 2,057 |
| | 2,858 |
|
| Number of Employees | 4,700 |
| | 4,400 |
| | 4,500 |
| | 5,800 |
| | 6,100 |
|
| |
(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,a $1.2 billion at December 31, 2012,one-time deferred tax benefit in 2017 related to Tax Reform Legislation and $494 million at December 31, 2011.a $4.4 billion Tronox-related contingent loss in 2014. |
| |
(3) | As a resultIncludes Tronox settlement payment of adopting Accounting Standards Update 2015-17, Balance Sheet Classification of Deferred Taxes, the Company reclassified other current assets of $722 million$5.2 billion 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. |
| |
(5) | Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel. |
|
| | | | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
Index | | | | | |
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 | | Contents
Index to Financial Statements |
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 |
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW | |
Anadarko’s mission isstrategic objectives are to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploringexplore 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
identifydevelop, and commercialize resources
employ a global business development approach
globally; ensure health, safety, and environmental excellence; focus on financial discipline, flexibility, 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-efficientcreation; 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 todemonstrate 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 investmentcore values in all 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.
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.business activities. 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,commodity prices, which affect the value the Company receives from its sales of oil, natural-gas,natural gas, and natural-gas liquids (NGLs) production. NGLs.
The Company’s strategyCompany continues to efficiently allocate capital in 2015 wasorder to preservegenerate attractive returns on, and build value by focusingof, capital while investing within cash flow. Anadarko also continues to focus on cash-margin improvement and has actively managed its portfolio to focus on higher-return, oil-levered opportunities in areas where it possesses both scale and competitive advantages, namely in the Delaware and DJ basins in the U.S. onshore and in the deepwater Gulf of Mexico. The Company plans to deploy a greater percentageportion of its capital investment on longer-dated projects while driving cost savingscash flow generated from its Gulf of Mexico, Algeria, Ghana, and efficiencies through every aspect of its business. During 2015,DJ basin assets to fund investments in other assets that generate attractive cash returns, thereby improving the Company closed $2.0 billion of monetizationsCompany’s overall long-term cash-flow profile and was successful in lowering its capital expenditures by 36% and its operating expenses by 13% comparedability to 2014 while maintaining relatively flat production year over year.continue returning cash to investors.
The Company plans to continue focusing on returning capital directly to 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.
investors. The Company will continuedemonstrated this focus in 2018 by increasing its quarterly cash dividend from $0.05 to evaluate the oil$0.30 per share, expanding its authorized Share-Repurchase Program to $5 billion, and natural-gas price environments and may adjustincreasing its capital spending plansdebt-reduction program 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 $2 billion. As of December 31, 2015, Anadarko2018, the Company had $939repurchased 65 million shares of cash on hand plus $4.75its common stock for an average price of $57.69 per share. The Company expects to complete the remaining $1.25 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 orauthorized share repurchases by using the Five-Year Facility.
mid-year 2020. As of December 31, 2015,2018, Anadarko had retired more than $600 million of debt and plans to repay $900 million of debt maturing in the first half of 2019. An additional $500 million of debt reduction is anticipated through mid-year 2020. These actions demonstrate the cash-flow-generating strength of the Company’s asset portfolio and the Company’s ongoing commitment to capital efficiency and returns.
At the end of 2018, the Company announced the planned contribution and sale of substantially all of its midstream assets not owned by WES, which are largely associated with Anadarko's two premier U.S. onshore oil plays in the Delaware and DJ basins, to WES for approximately $4.0 billion, with approximately $2.0 billion of cash proceeds and the balance to be paid in WES common units. This transaction is expected to increase WES’s cash distributions paid to Anadarko in 2019 and reduce Anadarko’s long-term debt was rated “BBB”future midstream capital funding requirements associated 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’sthe divested assets. Additionally, WES announced that it had placed both ratings under review for downgrade alonga wholly owned subsidiary of WGP will merge with and into WES to simplify its structure and lower 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 itsweighted-average cost of capital for the midstream entity via the elimination of incentive distribution rights. These transactions are expected to close in the first quarter of 2019 and a downgrade to a level thatshould result in enhanced liquidity of Anadarko’s residual ownership of WGP securities.
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW | |
The Company’s 2019 capital program is below investment grade could also adversely affectconsistent with the Company’s ability to effectively execute aspects of its strategy or to raise debtfocus on enhancing shareholder value by delivering attractive cash returns on invested capital in a $50 oil (for both WTI and Brent) and $3 natural-gas (Henry Hub) price environment while advancing the public debt markets.
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 assurancedevelopment of the Company’s performance under these typescore assets. Anadarko currently estimates a 2019 capital spending range of contractual arrangements with respect$4.3 billion to credit-risk-related contingent features. If Anadarko’s credit ratings had been downgraded$4.7 billion, excluding WES. Anadarko expects 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 1Aallocate approximately 70% of this Form 10-K.Furthermore,2019 capital investment to the U.S. onshore upstream and midstream resource plays; 16% to conventional oil plays in the eventdeepwater Gulf of Mexico, Algeria, and Ghana; 10% to future value areas, which includes 6% to exploration and 4% to Mozambique LNG activities, excluding post-FID incremental spend; and 4% to corporate activities. The Company’s asset footprint and strong balance sheet are intended to perform through commodity cycles.
| |
| – | Delaware Basin Anadarko plans to allocate approximately $1.4 billion toward upstream activities. The successful expansion of the Company’s infrastructure footprint, including oil gathering and treating facilities throughout West Texas, is paving the way to transition to multi-well pad development. This phased development approach is expected to deliver incremental oil sales volume in 2019. |
| |
| – | DJ Basin Anadarko expects to invest approximately $1.3 billion on upstream activities, with continued development of its minerals-interest ownership and infrastructure-advantaged position in the Wattenberg field. Anadarko expects to deliver incremental oil sales volume from the DJ basin in 2019. |
| |
| – | Powder River Basin Anadarko expects to invest approximately $250 million toward upstream activities, including appraisal and delineation of its 300,000 gross acre position in the southern Powder River basin primarily targeting the Turner formation. |
| |
| – | Gulf of Mexico Anadarko expects to allocate approximately $500 million toward its deepwater Gulf of Mexico operations. Although the capital allocation is lower than in 2018, the Company plans to deliver a similar number of wells in 2019 and maintain production levels around 140 MBOE/d. The majority of these investments are expected to be directed toward high-return oil development opportunities near operated infrastructure at Constellation, Holstein, Horn Mountain, K2, Lucius, and North Hadrian. |
| |
| – | International Anadarko plans to allocate approximately $200 million toward its international operations in Algeria and Ghana. The investment in Ghana will be focused on adding incremental wells to optimize capacity at the Jubilee and TEN FPSO vessels. |
| |
| – | Exploration The Company's exploration investments in 2019 are expected to total approximately $250 million. Exploration spending will primarily be focused on identifying material and scalable opportunities in the U.S. onshore and tie-back opportunities near existing operated facilities in the deepwater Gulf of Mexico. |
| |
| – | LNG The Company expects to invest approximately $200 million in the Mozambique LNG project in 2019 on pre-FID activities. This includes Anadarko’s portion of the cost associated with ongoing site preparation for the shared onshore facilities. The Company remains on track for making a final investment decision in the first half of 2019, and anticipates adjusting its capital investment expectations associated with the Mozambique LNG project if the project is sanctioned. |
WES currently estimates a
downgrade in Anadarko’s credit rating2019 total capital spending range of $1.3 to
a level that is below$1.4 billion. WES capital investment
grade, the credit thresholds with Anadarko’s derivative counterparties maywill be
reduced or, in certain cases, eliminated, which may require the Company to post additional collateralprimarily focused in the
formDJ and Delaware basins, with over 90% 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 Notesestimated 2019 total capital expenditures allocated 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.these two basins.
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.
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:
|
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| MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW | |
|
|
| Significant 2018 Operating and Financial Activities |
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.
| |
•– | The Company’s oil sales volume averaged 385 MBbls/d, representing a 9% increase from 2017, primarily due to increased volume from the DJ and Delaware basins, partially offset by the divestiture of certain U.S. onshore assets in 2017. |
| |
| – | The Company’s overall oil sales-volume product mix increased to 58% in 2018, compared to 53% in 2017. The overall liquids sales-volume product mix increased to 73% in 2018, compared to 67% in 2017. |
U.S. Onshore
| |
| – | Total sales volume in the Delaware basin averaged 109 MBOE/d, representing a 68% increase from 2017, and oil sales volume in the Delaware basin increased 27 MBbls/d, representing a 71% increase from 2017, primarily due to continued drilling and completion activities. |
| |
| – | In the Delaware basin, the Reeves and Loving County ROTFs were completed, with 138 total wells flowing into the facilities by the end of 2018. In addition, the first train at the WES-owned Mentone natural-gas processing plant was placed in service during the fourth quarter, adding 200 MMcf/d of natural-gas processing capacity. |
| |
| – | Anadarko paid $5.2 billion related to a settlement agreement resolving all claims assertedOil sales volume in the Tronox Adversary Proceeding. SeeDJ basin increased 14 MBbls/d, representing a Note 15—Contingencies—Tronox Litigation17% in the Notesincrease from 2017, primarily due to Consolidated Financial Statements under Item 8 of this Form 10-K.continued drilling and completion activities. |
| |
•– | After previously finding that Anadarko, as a nonoperating investorIn the DJ basin, the sixth COSF train was placed in service, adding 30 MBbls/d of oil-stabilization capacity.
|
| |
| – | The Company received net proceeds of approximately $370 million from the divestiture of its nonoperated interest in Alaska. |
Gulf of Mexico
| |
| – | Oil sales volume averaged 121 MBbls/d, remaining relatively flat compared to 2017, primarily due to natural production declines and planned downtime at various platforms, partially offset by new wells coming online at Horn Mountain, Holstein, Marlin, and Caesar Tonga. |
Ghana
| |
| – | In the TEN field, the operator resumed drilling operations in early 2018, with one well brought online in 2018. Two additional wells were drilled in 2018, with completion activities ongoing at year end. |
| |
| – | In the Jubilee field, the operator drilled two production wells during the second quarter of 2018, with the first of these wells brought online in the Macondothird quarter. The second 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 ownerbrought online in the Macondofourth quarter. Additionally, a previously drilled water injector well was brought online during the fourth quarter of 2018. |
| |
| – | The operator of the Jubilee FPSO completed two shutdowns to effectively stabilize the turret and entered a judgmentrotate the FPSO to its permanent heading. Completion of $159.5 millionthe spread-mooring anchoring system is expected 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.early 2019, with no further shutdowns anticipated. |
U.S. OnshoreAPC 2018 FORM 10-K | 59
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. |
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS MANAGEMENT OVERVIEW | |
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.
InternationalMozambique
| |
| – | During 2018 and subsequent to year end, additional LNG sales and purchase agreements were executed, increasing contracted volumes to more than 7.5 MTPA, with an additional 2.0 MTPA of contracted volume anticipated prior to FID. |
| |
| – | The Government of Mozambique approved the Development Plan for the Anadarko-operated, initial two-train Golfinho/Atum project. |
| |
| – | The preferred offshore construction and installation contractor was selected in the fourth quarter of 2018, and the contracts with the onshore and offshore construction and installation contractors are being finalized ahead of making a final investment decision in the first half of 2019. |
| |
| – | Site preparation activities are fully underway at the Afungi onshore site, as major infrastructure and resettlement projects are proceeding as planned, positioning the area for construction of the LNG facilities. |
| |
| – | In the third quarter of 2018, Offshore Area 4, which is owned and operated by third parties, joined the Anadarko-led resettlement and airstrip projects as a 50% participant. |
Financial
| |
| – | The Company generated $5.9 billion of cash flow from operations and ended 2018 with $1.3 billion of cash. |
| |
| – | The Company completed $2.7 billion of share repurchases and retired more than $600 million of debt. |
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.
Financial60 | APC 2018 FORM 10-K
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. |
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
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.
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 |
|
|
| | | | | | | | | | | |
| millions except per-share amounts | 2018 |
| | 2017 |
| | 2016 |
|
| Oil, natural-gas, and NGL sales | $ | 11,482 |
| | $ | 8,969 |
| | $ | 7,153 |
|
| Gathering, processing, and marketing sales | 1,588 |
| | 2,000 |
| | 1,294 |
|
| Gains (losses) on divestitures and other, net | 312 |
| | 939 |
| | (578 | ) |
| Revenues and other | $ | 13,382 |
| | $ | 11,908 |
| | $ | 7,869 |
|
| Costs and expenses | 10,763 |
| | 12,473 |
| | 10,241 |
|
| Other (income) expense | 1,134 |
| | 1,123 |
| | 1,457 |
|
| Income tax expense (benefit) | 733 |
| | (1,477 | ) | | (1,021 | ) |
| Net income (loss) attributable to common stockholders | $ | 615 |
| | $ | (456 | ) | | $ | (3,071 | ) |
| Net income (loss) per common share attributable to common stockholders—diluted | $ | 1.20 |
| | $ | (0.85 | ) | | $ | (5.90 | ) |
| Average number of common shares outstanding—diluted | 504 |
| | 548 |
| | 522 |
|
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, 2015,2018,” refer to the comparison of the year ended December 31, 2015,2018, to the year ended December 31, 2014.2017. Similarly, any increases or decreases “for the year ended December 31, 2014,2017,” refer to the comparison of the year ended December 31, 2014,2017, to the year ended December 31, 2013.2016. The primary factors that affect the Company’s results of operations include commodity prices for oil, natural gas, and NGLs; sales volumes;volume; the cost of finding and developing such reserves; and operating costs.
Revenues and Sales Volumes
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
|
| | | | | | | | | | | | | | | |
| 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 | % |
ChangesREVENUES AND SALES VOLUME
For 2018, the table below illustrates the effect of increases in commodity prices and changes associated with sales volumes forvolume. Sales volume changes during 2018 included increases associated with continued drilling and completion activities in the years ended December 31, 2015Delaware and 2014, includeDJ basins and decreases associated with U.S. onshore asset divestitures.
The following provides Anadarko’s sales volumesvolume 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 |
|
|
| | | | | | | | | | | | | |
| | Barrels of Oil Equivalent (MMBOE) | | Barrels of Oil Equivalent per Day (MBOE/d) |
| | 2018 |
| 2017 |
| 2016 |
| | 2018 |
| 2017 |
| 2016 |
|
| United States | 208 |
| 211 |
| 257 |
| | 570 |
| 579 |
| 704 |
|
| International | 35 |
| 34 |
| 33 |
| | 96 |
| 93 |
| 89 |
|
| Total | 243 |
| 245 |
| 290 |
| | 666 |
| 672 |
| 793 |
|
_______________________________________________________________________________MMBOE—million barrels of oil equivalent
Sales volumes representvolume represents actual production volumesvolume adjusted for changes in commodity inventories andas well as natural-gas production volumesvolume provided to satisfy a commitment established in conjunction withunder 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—11—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.10-K. Production of oil, natural gas, oil, and NGLs is usually not affected by seasonal swings in demand.
5662 | APC 2018 FORM 10-K
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
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 |
|
|
|
| Oil Sales Revenues, Average Prices, and Volume |
_______________________________________________________________________________
|
| | | | | | | | | | | |
| | 2018 |
| | 2017 |
| | 2016 |
|
| Oil sales revenues (millions) | $ | 9,206 |
| | $ | 6,552 |
| | $ | 4,668 |
|
| | | | | | |
| Price per barrel | | | | | |
| United States | $ | 64.01 |
| | $ | 49.62 |
| | $ | 39.06 |
|
| International | 70.38 |
| | 53.77 |
| | 43.93 |
|
| Total | $ | 65.51 |
| | $ | 50.66 |
| | $ | 40.34 |
|
| | | | | | |
| Sales volume (MMBbls) | | | | | |
| United States | 108 |
| | 97 |
| | 85 |
|
| International | 33 |
| | 32 |
| | 31 |
|
| Total | 141 |
| | 129 |
| | 116 |
|
| | | | | | |
| Sales volume per day (MBbls/d) | | | | | |
| United States | 294 |
| | 266 |
| | 233 |
|
| International | 91 |
| | 89 |
| | 83 |
|
| Total | 385 |
| | 355 |
| | 316 |
|
Oil and Condensate Sales VolumesPrices
2015 vs. 2014
Anadarko’s realized oil and condensate sales volumes price increased by 25 MBbls/d.
Sales volumes in the Rockies increased by 11 MBbls/dlate 2016 through 2017, primarily in the Wattenberg field due to continued horizontal drilling, partially offset by lower sales volumes due to the saleexpectation of certain EOR assets in April 2015.
Sales volumes in the Southern and Appalachia Region increased by 10 MBbls/d primarily in the Eagleford shaledecreasing global oversupply as a result of OPEC’s agreement to reduce production through the end of 2018. Oil prices continued horizontal drilling and in the Delaware basinto increase during most of 2018, primarily due to wells brought onlineconcerns of a supply shortfall as a result of additional infrastructure and continued drilling.reductions in output from Iran as the U.S. reimposed sanctions, as well as decreased production from Venezuela. Oil prices declined in the fourth quarter of 2018 due to concerns of oil demand weakness from a slowing global economy.
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
Oil Sales volumes in the Gulf of Mexico Volume
increased2018 vs. 2017 The Company’s oil sales volume 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 430 MBbls/d, primarily due to the timingfollowing:
U.S. Onshore
| |
| – | Sales volume for the Delaware basin increased by 27 MBbls/d, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2018. |
| |
| – | Sales volume for the DJ basin increased by 14 MBbls/d, primarily due to continued drilling and completion activities in 2018. |
| |
| – | Divestitures resulted in decreased sales volume of 16 MBbls/d, primarily related to the sale of the Alaska nonoperated assets in the first quarter of 2018 and the Eagleford and West Chalk assets in the first half of 2017. |
Gulf 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.Mexico
| |
| – | Sales volume for the Gulf of Mexico remained flat, primarily due to natural production declines and planned downtime at various platforms, partially offset by new wells coming online at Horn Mountain, Holstein, Marlin, and Caesar Tonga throughout 2018. |
20142017 vs. 2013 2016Anadarko’s The Company’s oil and condensate sales volumesvolume 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 139 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.following:
Sales volumesU.S. Onshore
| |
| – | Sales volume for the Delaware basin increased by 13 MBbls/d, primarily due to continued drilling and completion activities in 2017. |
| |
| – | Divestitures resulted in a decrease in sales volume of 29 MBbls/d, primarily related to the sale of the Eagleford assets in the first half of 2017. |
Gulf of Mexico decreased by 1 MBbls/d primarily due to natural production declines.
| |
| – | Sales volume increased by 56 MBbls/d, primarily due to the GOM Acquisition in December 2016 and continued tie-back activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey, Irma, and Nate and nonoperated field downtime during the second half of 2017. |
International
| |
| – | Sales volume for Ghana increased by 9 MBbls/d, primarily due to a full year of liftings from the TEN development, which came online late in the third quarter of 2016, and downtime in 2016 to address new production and offtake procedures resulting from issues associated with the Jubilee field FPSO turret bearing. |
Oil and Condensate Prices
2015 vs. 201464 Anadarko’s average oil price received decreased primarily as a result of global oversupply.| APC 2018 FORM 10-K
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
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.
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 |
|
|
|
| Natural-Gas Sales Revenues, Volume, and Average Prices |
_______________________________________________________________________________
MMcf/d—million cubic feet per day |
| | | | | | | | | | | |
| | 2018 |
| | 2017 |
| | 2016 |
|
| Natural-gas sales revenues (millions) | $ | 1,005 |
| | $ | 1,348 |
| | $ | 1,564 |
|
| | | | | | |
| Price per Mcf | $ | 2.57 |
| | $ | 2.82 |
| | $ | 2.04 |
|
| | | | | | |
Sales volume (Bcf) (1) | 390 |
| | 478 |
| | 766 |
|
Sales volume per day (MMcf/d) (1) | 1,069 |
| | 1,309 |
| | 2,093 |
|
Mcf—thousand cubic feet | |
(1) | All natural-gas sales volume originates in the United States. |
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
Anadarko’s realized natural-gas price Anadarko received decreasedincreased from 2016 to 2017, primarily due to a reduction of U.S. natural-gas storage resulting from production declines across the industry from mid-2016 through early 2017 and stable exports to Mexico throughout 2017. In 2018, NYMEX prices were higher due to strong year-over-yeardemand growth and low U.S. natural-gas storage. However, Anadarko’s realized natural-gas price decreased in 2018 due to wider regional differentials in its operated basins as strong production growth in the northeast United StatesDelaware and slightly lower weather-driven residentialDJ basins required higher utilization of gas pipeline takeaway capacity.
Natural-Gas Sales Volume
2018 vs. 2017 The Company’s natural-gas sales volume decreased by 240 MMcf/d, primarily due to the sale of the Marcellus, Eagleford, and commercial demand mainlyUtah CBM assets in the first half of 2015.2017 and the Moxa assets in the second half of 2017.
20142017 vs. 2013 2016The averageCompany’s natural-gas price Anadarko received increasedsales volume decreased by 784 MMcf/d, primarily due to low industry natural-gas storage levels as a resultthe sale of colder than average winter temperaturesthe Marcellus and Eagleford assets in the first half of 2017, the Carthage and Elm Grove assets in the second half of 2016, and the associated high residential heating demandWamsutter assets in early 2014. In addition, natural-gas prices increased as a resultthe first half of higher industrial natural-gas demand, reduced natural-gas imports from Canada, and continued strength in exports to Mexico.2016.
58APC 2018 FORM 10-K | 65
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
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 |
|
|
|
| Natural-Gas Liquids Sales Revenues, Volume, and Average Prices |
NM—not meaningful
|
| | | | | | | | | | | |
| | 2018 |
| | 2017 |
| | 2016 |
|
| Natural-gas liquids sales revenues (millions) | $ | 1,271 |
| | $ | 1,069 |
| | $ | 921 |
|
| | | | | | |
| Price per barrel | $ | 33.93 |
| | $ | 29.54 |
| | $ | 19.64 |
|
| | | | | |
Sales volume (MMBbls) (1) | 37 |
| | 36 |
| | 46 |
|
Sales volume per day (MBbls/d) (1) | 103 |
| | 99 |
| | 128 |
|
| |
(1) | Approximately 95% of NGL sales volume was from the United States. |
NGL Prices
Anadarko’s realized NGL price increased from 2016 to 2017, primarily due to increased domestic demand and higher exports. The average NGL price continued to increase during most of 2018, primarily due to increased demand for ethane to supply newly-constructed ethane cracker facilities. NGL prices declined in the fourth quarter of 2018 due to higher gas plant production of NGLs and loosening of infrastructure constraints.
NGL Sales VolumesVolume
NGLs
2018 vs. 2017 The Company’s NGL sales represent revenues fromvolume increased by 4 MBbls/d, primarily due to the following:
U.S. Onshore
| |
| – | Sales volume for the Delaware basin increased by 9 MBbls/d, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2018. |
| |
| – | Sales volume for other U.S. onshore assets decreased by 5 MBbls/d, primarily due to the sale of the Eagleford and West Chalk assets in the first half of 2017 and the Moxa assets in the second half of 2017. |
2017 vs. 2016 The Company’s NGL sales volume decreased by 29 MBbls/d, primarily due to 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 volumesEagleford assets in the Rockies increased by 6 MBbls/d primarilyfirst half of 2017 and the Carthage assets 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 commencementsecond half 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.2016.
2014 vs. 201366 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.| APC 2018 FORM 10-K
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
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, Processing, and Marketing |
|
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
Gathering, processing, and marketing sales (1) | $ | 1,588 |
| | $ | 2,000 |
| | $ | 1,294 |
|
Gathering, processing, and marketing expense (1) | 1,047 |
| | 1,552 |
| | 1,083 |
|
| Gathering, processing, and marketing, net | $ | 541 |
| | $ | 448 |
| | $ | 211 |
|
| |
(1) | As a result of adopting ASU 2014-09, Revenue from Contracts with Customers (Topic 606), as of January 1, 2018, gathering, processing, and marketing sales decreased by $1.0 billion for the year ended December 31, 2018, and gathering, processing, and marketing expenses decreased by $1.0 billion for the year ended December 31, 2018. Refer to Note 2—Revenue from Contracts with Customersin the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information. |
Gathering and processing sales includesinclude fee revenue earned by providing gathering, processing, compression, and treating services to third parties as well as revenue from the sale of NGLs and remaining residue gas extracted from natural gas purchased from third parties and processed by Anadarko. The net margin from the sale of NGLs and residue gas for service customers when Anadarko is acting as well as fee revenue earned by providing gathering,an agent is also included. Gathering and 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 transportation and other operating and transportation expenses related to the Company’s costs to perform gathering and processing activities for third parties.
Marketing sales include the margin earned from purchasing and selling third-party oil and natural gas. Marketing expense includes transportation and other operating expenses related to the Company’s costs to perform third-party marketing activities.
20152018 vs. 2014 2017Gathering, 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$93 million. This increase primarily related to higher third-party throughput volume at the West Texas Complex, which were partially due to higher gathering and processing revenue associated with higher volumes, increased natural-gas prices,capacity from the 200 MMcf/d cryogenic train that commenced service in December 2017, and increased infrastructure,third-party throughput volume and rates at the DJ Basin Complex. These increases were partially offset by higherdecreased marketing margins related to pricing on NGL inventory.
2017 vs. 2016Gathering, processing, and transportation expensesmarketing, net increased by $237 million. This increase primarily related to higher third-party throughput volume and prices at the DBM Complex due to increased processing capacity from the increased volumes.start-up of newly constructed facilities in May and October 2016 and previously existing facilities returning to service after the 2016 outage at the DBM Complex.
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 |
|
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
| Gains (losses) on divestitures, net | $ | 20 |
| | $ | 674 |
| | $ | (757 | ) |
| Other | 292 |
| | 265 |
| | 179 |
|
| Total gains (losses) on divestitures and other, net | $ | 312 |
| | $ | 939 |
| | $ | (578 | ) |
Gains (losses) on divestitures and other, net includes gains (losses) on divestitures and other operating revenues, including hard-minerals royalties, earnings (losses) from equity investments, hard-minerals royalties, and other revenues.
2015
The Company recognized a loss of $538 million associated withDuring the divestiture ofyears presented, Anadarko divested certain coalbed methane propertiesnon-core U.S. onshore 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.
61APC 2018 FORM 10-K | 67
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
Costs
COSTS AND EXPENSES
The following provides Anadarko’s total costs and Expensesexpenses for the years ended December 31:
|
| | | | | | | | | | | | | | | | | |
| | 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 |
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
| Oil and gas operating | $ | 1,153 |
| | $ | 988 |
| | $ | 807 |
|
| Oil and gas transportation | 878 |
| | 914 |
| | 1,002 |
|
| Exploration | 459 |
| | 2,535 |
| | 944 |
|
| Gathering, processing, and marketing | 1,047 |
| | 1,552 |
| | 1,083 |
|
| G&A | 1,084 |
| | 994 |
| | 1,223 |
|
| DD&A | 4,254 |
| | 4,279 |
| | 4,301 |
|
| Production, property, and other taxes | 826 |
| | 582 |
| | 536 |
|
| Impairments | 800 |
| | 408 |
| | 227 |
|
| Other operating expense | 262 |
| | 221 |
| | 118 |
|
| Total | $ | 10,763 |
| | $ | 12,473 |
| | $ | 10,241 |
|
Oil and Gas Operating Expenses2015 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. |
|
| Oil and Gas Operating Expenses |
|
| | | | | | | | | | | |
| | 2018 |
| | 2017 |
| | 2016 |
|
| Oil and gas operating (millions) | $ | 1,153 |
| | $ | 988 |
| | $ | 807 |
|
| Oil and gas operating—per BOE | 4.74 |
| | 4.03 |
| | 2.78 |
|
20142018 vs. 2013 2017Oil and gas operating expenses increased by $79$165 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 werefollowing:
| |
| – | higher U.S. onshore costs of $140 million, primarily related to increased operating and nonoperating activity in the DJ and Delaware basins, partially offset by lower expenses of $74 million as a result of U.S. onshore asset divestitures |
| |
| – | higher non-operating costs of $54 million in Ghana, primarily due to the Jubilee FPSO turret repair and additional wells coming online in 2018 |
| |
| – | higher operating costs of $32 million, primarily related to maintenance at various platforms in GOM |
2017 vs. 2016Oil and gas operating expenses increased by $181 million, primarily due to the sales of the Company’s Pinedale/Jonah assets and its Chinese subsidiary. following:
| |
| – | higher operating costs of $212 million, primarily related to the GOM Acquisition |
| |
| – | higher operating costs of $84 million related to increased activity in the DJ and Delaware basins and costs related to the Company’s response efforts in Colorado in 2017 |
| |
| – | lower nonoperating costs of $12 million in Ghana, primarily related to FPSO maintenance costs in 2016, partially offset by higher costs in 2017 due to increased production from the TEN development, which came online late in the third quarter of 2016 |
| |
| – | lower expenses of $89 million as a result of U.S. onshore asset divestitures |
The related costs per BOE decreased by $0.02increased from 2016 to 2018, primarily due to increased costs as a result of shifting to a higher-return, oil-levered portfolio that includes the Gulf of Mexico and Delaware basin, which operate at a higher cost compared to the lower-return, gas-levered divested assets.
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
|
|
| Oil and Gas Transportation Expenses |
|
| | | | | | | | | | | |
| | 2018 |
| | 2017 |
| | 2016 |
|
| Oil and gas transportation (millions) | $ | 878 |
| | $ | 914 |
| | $ | 1,002 |
|
| Oil and gas transportation—per BOE | 3.61 |
| | 3.73 |
| | 3.46 |
|
2018 vs. 2017 Oil and gas transportation expenses decreased by $36 million, primarily due to U.S. onshore divestitures and increased transportation costs related to sales volumes,from storage in 2017, partially offset by increased oil sales volume in the higher costs.Delaware basin in 2018. Oil and gas transportation expenses per BOE remained relatively flat.
Oil and Gas Transportation Expenses
20152017 vs. 2014 2016Oil and gas transportation expenses were relatively flat.decreased by $88 million, primarily due to 2017 and 2016 U.S. onshore divestitures, partially offset by increased oil and gas sales volume in the Gulf of Mexico and increased rates in the DJ basin. Oil and gas transportation expenses per BOE increased by $0.03$0.27 primarily due to decreased sales volumes.increased oil and natural-gas transportation rates in the DJ basin.
|
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
| Dry hole expense | $ | 87 |
| | $ | 1,433 |
| | $ | 397 |
|
| Impairments of unproved properties | 159 |
| | 788 |
| | 216 |
|
| Geological and geophysical, exploration overhead, and other expense | 213 |
| | 314 |
| | 331 |
|
| Total exploration expense | $ | 459 |
| | $ | 2,535 |
| | $ | 944 |
|
Dry Hole Expense
2018
| |
| – | $87 million related to unsuccessful drilling activities, primarily in the Gulf of Mexico |
2017
| |
| – | $437 million related to the Shenandoah project, $215 million related to the Phobos project, and $108 million related to the Warrior project in the Gulf of Mexico due to insufficient quantities of oil pay to justify development |
| |
| – | $329 million related to all remaining wells in Côte d’Ivoire, where the Company relinquished its interest in all of its exploration blocks |
| |
| – | $243 million related to certain wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater natural-gas development |
2016
| |
| – | $231 million related to certain wells in the Gulf of Mexico and $92 million related to certain wells in Mozambique |
| |
| – | $39 million for a well in Côte d’Ivoire that finished drilling in the third quarter of 2016 and encountered noncommercial quantities of hydrocarbons |
Impairments of Unproved Properties
For discussion related to impairments of unproved properties, see Note 6—Impairmentsin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-K.
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
|
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
| G&A | $ | 1,084 |
| | $ | 994 |
| | $ | 1,223 |
|
2018 vs. 2013 2017Oil and gas transportation expensesG&A increased by $135$90 million, primarily due to an increase in employee-related expenses of $31 million, higher gas-gatheringlegal and transportationconsulting fees of $23 million and higher contract labor 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.of $13 million.
|
| | | | | | | | | | | |
| 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 |
|
|
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
| DD&A | $ | 4,254 |
| | $ | 4,279 |
| | $ | 4,301 |
|
20152018 vs. 2014 2017ExplorationDD&A expense decreased by $25 million, primarily due to the following:
| |
| – | $140 million decrease, primarily related to divestitures associated with U.S. onshore properties in 2018 and 2017 and a lower DD&A rate in 2018 driven by increased proved developed reserves in Ghana |
These decreases were offset by the following:
| |
| – | $62 million increase in ARO accretion expense due to increased ARO estimates in the Gulf of Mexico |
| |
| – | $53 million increase in straight line depreciation related to newly constructed pipelines and salt water disposal facilities in the Delaware basin |
2017 vs. 2016DD&A expense decreased by $22 million, primarily due to the following:
| |
| – | $717 million related to lower 2017 sales volume and asset property balances associated with U.S. onshore properties as a result of divestitures in 2016 and 2017 |
These decreases were offset by the following:
| |
| – | $457 million related to higher sales volume in the Gulf of Mexico, primarily due to the GOM Acquisition |
| |
| – | $240 million related to international production DD&A, primarily due to higher sales volume from the Ghana TEN project, which came online late in the third quarter of 2016 |
|
|
| Production, Property, and Other Taxes |
|
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
| U.S. production and severance taxes | $ | 164 |
| | $ | 90 |
| | $ | 80 |
|
| Algeria exceptional profits taxes | 405 |
| | 289 |
| | 280 |
|
| Ad valorem taxes | 254 |
| | 196 |
| | 163 |
|
| Other | 3 |
| | 7 |
| | 13 |
|
| Total production, property, and other taxes | $ | 826 |
| | $ | 582 |
| | $ | 536 |
|
2018 vs. 2017Production, property and other taxes increased by $1.0 billion.$244 million, primarily due to an increase in ad valorem and U.S. production and severance taxes driven by higher sales volume and commodity prices in the Delaware and DJ basins. Additionally, Algeria exceptional profits taxes increased due to higher commodity prices.
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 environment2017 vs. 2016Production, property and other considerations.taxes increased by $46 million, primarily due to an increase in commodity prices.
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
The Company recognized $306 million due to unsuccessful drilling activities expensed in 2015 primarily in Colombia and the Gulf of Mexico.following impairments for the years ended December 31:
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. |
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
| Exploration and Production | | | | | |
| U.S. onshore properties | $ | 347 |
| | $ | 2 |
| | $ | 28 |
|
| Gulf of Mexico properties | 27 |
| | 227 |
| | 27 |
|
| Cost-method investment | — |
| | — |
| | 59 |
|
| WES Midstream | 228 |
| | 176 |
| | 16 |
|
| Other Midstream | 53 |
| | 2 |
| | 57 |
|
| Other | 145 |
| | 1 |
| | 40 |
|
| Total impairments | $ | 800 |
| | $ | 408 |
| | $ | 227 |
|
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.
|
| | | | | | | | | | | | | | | | | |
| 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.
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—6—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 NGLsNGL 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.
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 InterestThe following provides Anadarko’s other (income) 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 $5.0years ended December 31:
|
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
Interest expense (1) | $ | 947 |
| | $ | 932 |
| | $ | 890 |
|
(Gains) losses on early extinguishment of debt (2) | (2 | ) | | 2 |
| | 155 |
|
(Gains) losses on derivatives, net (3) | 130 |
| | 135 |
| | 286 |
|
| Other (income) expense, net | 59 |
| | 54 |
| | 126 |
|
| Total | $ | 1,134 |
| | $ | 1,123 |
| | $ | 1,457 |
|
| |
(1) | Interest expense increased from 2016 to 2017 primarily due to lower capitalized interest in 2017. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS | |
|
|
| Income Tax Expense (Benefit) |
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 | 2018 |
| | 2017 |
| | 2016 |
|
| Income tax expense (benefit) | $ | 733 |
| | $ | (1,477 | ) | | $ | (1,021 | ) |
| Income (loss) before income taxes | $ | 1,485 |
| | $ | (1,688 | ) | | $ | (3,829 | ) |
| Effective tax rate | 49 | % | | 88 | % | | 27 | % |
In 2017, as a result of the Tax Reform Legislation, the Company recognized a one-time deferred tax benefit of $1.2 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 completionremeasurement of its U.S. deferred tax assets and liabilities, resulting in an 88% effective tax rate. Excluding this one-time benefit, the Company’s effective tax rate would have been 18%. The Company remeasured its U.S. deferred tax assets and liabilities based on the reduction of the Lucius developmentU.S. corporate tax rate from 35% to 21%. After completing the accounting for income tax effects related to the adoption of the Tax Reform Legislation in 2018, the Company revised the provisional amount and lower construction-in-progress balances for long-term capital projects in Brazil, partiallyrecognized an additional current tax benefit of $26 million offset by higher construction-in-progress balances for long-term capital projects primarilydeferred tax expense of $121 million. Excluding the impact from the Tax Reform Legislation, the Company’s 2018 effective tax rate would have been 43%.
The Company’s effective tax rate is impacted each year by the relative pre-tax income (loss) earned by the Company’s operations 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 projectU.S., Algeria, 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 valuerest of the Company’s derivative instruments as a resultworld. The Company is subject to statutory tax rates of changes38% in commodity pricesAlgeria and interest rates35% in Ghana. These higher-taxed foreign operations 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.
|
| | | | | | | | | | | |
| 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.
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 generally cause the Company’s effective tax positions
dispositions of non-deductible goodwill
The increaserate to vary significantly from the 35% U.S. federal statutorycorporate tax rate. Additionally, the Company’s effective tax rate for the year ended December 31, 2014, was primarily attributable to the following:
is typically impacted by net changes in uncertain tax positions, income attributable to noncontrolling interests, state income taxes (net of federal benefit), and dispositions of non-deductible goodwill. Excluding the impact related to the Tax Reform Legislation in 2017 and 2018, the Company’s effective tax rate increased from 18% in 2017 to 43% in 2018 primarily due to higher-taxed income earned in Algeria relative to the Company’s pretax income in the United States. The Company’s effective tax rate decreased from 27% in 2016 to 18% in 2017, primarily due to the higher-taxed income earned in Algeria relative to the Company’s pretax losses in the U.S. and Ghana as well as the impact of international exploration pretax losses with no associated tax benefit.
The Company received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox settlement agreement associatedpayment in 2015. In April 2018, the IRS issued a final notice of proposed adjustment denying the deductibility of the settlement payment. In September 2018, the Company received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting the Company’s refund claim. As a result, the Company filed a petition with the Tronox Adversary Proceeding
U.S. Tax Court to dispute the disallowances in November 2018, and pursuant to standard U.S. Tax Court procedures, is not required to repay the $881 million refund to dispute the IRS’s position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. After the case is tried and briefed in the Tax Court, the court will issue an opinion and then enter a decision. If the Company does not prevail on the issue, the earliest potential date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such time, the Company would reverse the portion of the $346 million net changesbenefit previously recognized in otherits consolidated financial statements to the extent necessary to reflect the result of the Tax Court decision. It is reasonably possible the amount of uncertain tax positions
non-deductible Algerian exceptional profitsposition and/or tax for Algerian income tax purposes
tax impact from foreign operations
The increase frombenefit could materially change as the 35% U.S. federal statutory rate forCompany asserts its position in the year ended December 31, 2013, was primarily attributableTax Court proceedings. Although management cannot predict the timing of a final resolution of the Tax Court proceedings, the Company does not anticipate a decision to be entered within the following:
tax impact from foreign operations
non-deductible Algerian exceptional profits tax for Algerian income tax purposes
deferred tax adjustments
next three years.
For additional information on income tax rates,taxes, see Note 12—14—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Net Income (Loss) Attributable to Noncontrolling Interests
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES | |
|
| | | | | | | | | | | |
| 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.
|
|
| 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 | % |
|
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
| Net cash provided by (used in) operating activities | $ | 5,929 |
| | $ | 4,009 |
| | $ | 3,000 |
|
| Net cash provided by (used in) investing activities | (5,982 | ) | | (1,030 | ) | | (2,742 | ) |
| Net cash provided by (used in) financing activities | (3,177 | ) | | (1,613 | ) | | 2,008 |
|
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 asset divestitures and joint-venture arrangements that reduce future capital expenditures, and the Company’s credit facilitiesfacility, and commercial paper program.access to both debt and equity capital markets. In addition, an effective registration statement is available to Anadarko covering the sale of WGP common units owned by the Company. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units.
During 2018, Anadarko repurchased $2.7 billion of shares under the Share-Repurchase Program, retired more than $600 million of debt, and received net proceeds of $417 million from divestitures, primarily related to the sale of the Company’s nonoperated interests in Alaska. Anadarko had $1.3 billion of cash at December 31, 2018. Following the expiration of the 364-Day Facility in January 2019, the Company has $3.0 billion of borrowing capacity under the APC RCF. Anadarko believes that its current available cash, anticipated proceeds from the sale of midstream assets to WES, and future operating cash flows will be sufficient to fund the Company’s projected long-term operational and capital programs, fund the increased dividends, and complete both the Share-Repurchase Program and the debt-reduction program. The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of current and expected conditions.
In order to reduce commodity-price risk and increase the predictability of 2019 cash flows, the Company entered into strategic derivative positions covering approximately 21% of its anticipated oil sales volume for 2019. The Company entered into three-way collars for 87 MBbls/d, consisting of a sold call at $72.98, a purchased put at $56.72, and a sold put at $46.72. See Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
As of December 31, 2018, the Company’s long-term debt was rated investment grade (BBB) by both S&P and Fitch and below investment grade (Ba1) by Moody’s. Subsequent to year end, Moody’s changed its outlook with respect to its rating from stable to positive. As a result of Moody’s Ba1 rating, Anadarko is more likely to be required to post collateral in the form of letters of credit or cash under certain contractual arrangements, such as derivative instruments, pipeline transportation contracts, and oil and gas sales contracts. Collateral related to credit-risk-related contingent features for which a net liability position existed was $66 million at December 31, 2018, and $170 million at December 31, 2017. For more information on credit-risk considerations, see Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. The amount of letters of credit or cash provided as assurance of the Company’s performance under pipeline transportation contracts and oil and gas sales contracts with respect to credit-risk-related contingent features was $260 million at December 31, 2018, and $263 million at December 31, 2017.
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES | |
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 periodically entering into commodity derivatives. Sales volumeSales-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 dueinterest payments related 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.Company’s outstanding debt.
Cash flows from operating activities were $5.9 billion for 2014 decreased2018, $1.9 billion higher compared to 2017, primarily due to $730higher sales revenues resulting from higher oil prices.
Cash flows from operating activities were $4.0 billion for 2017, $1.0 billion higher compared to 2016, primarily due to higher sales revenues resulting from higher commodity prices. Additional significant items impacting operating activities for 2016 were the $159.5 million payment of cash receivedthe Clean Water Act (CWA) penalty, $247 million related to severance costs and retirement benefits paid in 2013 associatedconnection with the Algeria exceptional profitsworkforce reduction program, and the receipt of an $881 million tax settlement, a $520 millionrefund related to the income tax payment in 2014benefit 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, higher2015 tax net 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.
loss carryback.
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—Contingencies14—Income Taxes—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.10-K for discussion related to the potential repayment of the 2016 tax refund.
Pension and Other Postretirement Contributions Contributions to the pension and other postretirement plans were $58$244 million in 2015, $1362018, $276 million in 2014,2017, and $174$120 million in 2013.2016. The Company expects to contribute $46$155 million in 20162019 to its pension and other postretirement plans.
6974 | APC 2018 FORM 10-K
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES | |
Investing Activities
Capital Expenditures The following presents the Company’s capital expenditures:
| | | millions | 2015 | | 2014 | | 2013 | 2018 |
| | 2017 |
| | 2016 |
|
| Cash Flows from Investing Activities | | | | | | | | | | |
| Additions to properties and equipment and dry holes | $ | 6,067 |
| | $ | 9,508 |
| | $ | 7,721 |
| |
Additions to properties and equipment (1) | | $ | 6,183 |
| | $ | 5,031 |
| | $ | 3,505 |
|
| Adjustments for capital expenditures | | | | | | | | | | |
| Changes in capital accruals | (226 | ) | | (237 | ) | | 246 |
| (3 | ) | | 275 |
| | (205 | ) |
| Corporate acquisitions | — |
| | — |
| | 475 |
| |
| Other | 47 |
| | (15 | ) | | 81 |
| 5 |
| | (6 | ) | | 14 |
|
Total capital expenditures (1) | $ | 5,888 |
| | $ | 9,256 |
| | $ | 8,523 |
| |
Total capital expenditures (2) | | $ | 6,185 |
| | $ | 5,300 |
| | $ | 3,314 |
|
| | | | | | | |
| Exploration and Production and other capital expenditures | | $ | 4,264 |
| | $ | 3,884 |
| | $ | 2,763 |
|
| WES Midstream capital expenditures | | 1,178 |
| | 956 |
| | 491 |
|
| Other Midstream capital expenditures | | 743 |
| | 460 |
| | 60 |
|
| |
(1) | Includes WESAdditions to properties and equipment as presented within Anadarko’s cash flows from investing activities include cash payments for cost of properties, equipment, and facilities. The cost of properties includes the initial capitalization of drilling costs associated with all exploratory wells, whether or not they were deemed to have a commercially sufficient quantity of proved reserves. |
| |
(2) | Capital expenditures exclude the FPSO capital expenditures of $525 million in 2015, $696 million in 2014, and $792 million in 2013.lease asset; see Financing Activities—Capital Lease Obligations below. |
During 2015, cash from operations and property divestitures were the primary sources for funding capital investments.2018 vs. 2017 The Company’s capital expenditures decreasedincreased by 36%$885 million for the year ended December 31, 2015,2018. Exploration and Production capital expenditures increased primarily due to reduced development and exploration activity, which resulted in decreasedhigher development costs of $2.1 billion$809 million driven by increased drilling and completion activities primarily in the RockiesDJ and the Southern and Appalachia Region; lower exploration costs of $710 million primarily in the Southern and Appalachia RegionDelaware basins and the Gulf of Mexico;Mexico. Exploration costs decreased by $485 million primarily related to decreased exploration drilling in the Gulf of Mexico, Côte d’Ivoire, and lower gathering, processing,Colombia. Other Midstream capital expenditures increased $283 million due to infrastructure build-out primarily in the Delaware basin. WES Midstream capital expenditures increased $222 million primarily related to infrastructure build-out in the Delaware and otherDJ basins.
2017 vs. 2016 The Company’s capital expenditures increased by $2.0 billion for the year ended December 31, 2017. Exploration and Production capital expenditures increased primarily due to higher development costs of $498$925 million driven by increased U.S. onshore drilling activity primarily in the DJ basin and operatorship capture in the Delaware basin as well as higher exploration costs of $356 million primarily driven by U.S. onshore acreage acquisitions and $172 million primarily due to lower expenditures for plants and gathering in the Rockies. Development acquisitions in 2014 included a spar lease buyout of $110 millionexploration drilling 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 acquisitionsdecreased development costs of certain$227 million driven by the TEN development in Ghana, which achieved first oil and gas properties and related assets in the Moxa areathird quarter of Wyoming for $3102016. WES Midstream capital expenditures increased primarily due to $465 million related to the development of assets primarily representingin the fair valueDelaware and DJ basins. Other Midstream capital expenditures increased $400 million due to asset development primarily in the Delaware basin.
Property Exchange On March 17, 2017, WES acquired a third party’s 50% nonoperated interest in the DBJV System, now part of the oil and gas properties acquired, and the acquisition of aWest Texas Complex, in exchange for WES’s 33.75% interest in gas-gathering systems locatednonoperated Marcellus midstream assets and $155 million in cash. WES funded the Marcellus shale in north-central Pennsylvania fromcash considerationwithcashonhandandrecognized a third partygainof$126 million as a result of this transaction. After the acquisition, the DBJV System was 100% owned by WES for $135 million.
Carried-Interest ArrangementsIn 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.consolidated by Anadarko. See Note 3—Acquisitions, 4—Divestitures and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
AcquisitionsIn December 2016, the Company closed the GOM Acquisition for $1.8 billion.
Investments The Company made capital contributions for equity investments of $303 million in 2018, $29 million in 2017, and $62 million in 2016, which are presented as cash flows from investing activities as a component of Other, net. These contributions were primarily associated with joint ventures for the Midland-to-Sealy and Cactus II pipelines in West Texas in 2018, the Ranch Westex natural-gas processing plant in West Texas in 2017, and the Saddlehorn-Grand Mesa pipeline in Colorado in 2016.
Divestitures Anadarko received pretax salesnet proceeds related tofrom property divestiture transactionsdivestitures of $1.4$417 million in 2018, $4.0 billion in 2015, $5.02017, and $2.4 billion in 2014, and $567 million in 2013.2016. See Note 3—Acquisitions, 4—Divestitures and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
70APC 2018 FORM 10-K | 75
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES | |
|
| | | | | | | |
| | December 31, |
| millions except percentages | 2018 |
| | 2017 |
|
| Anadarko | $ | 11,602 |
| | $ | 12,196 |
|
| WES | 4,787 |
| | 3,465 |
|
| WGP | 28 |
| | 28 |
|
| Total debt | $ | 16,417 |
| | $ | 15,689 |
|
| Total equity | 10,943 |
| | 13,790 |
|
| Consolidated debt to total capitalization ratio | 60.0 | % | | 53.2 | % |
Debt-reduction Program The Company has commenced a $2.0 billion debt-reduction program. As of December 31, 2018, Anadarko had retired more than $600 million of debt and plans to Financial Statements
Investments Capital contributions for equity investments are included in Other, net under Investing Activitiesrepay $900 million of debt maturing in the Company’s Consolidated Statementfirst half of Cash Flows. The Company made capital contributions for equity investments2019. An additional $500 million 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.debt reduction is anticipated through mid-year 2020.
Financing Activities Credit Facilities
Senior Notes APC RCFsThe 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 $1.2Company has a $3.0 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 athat matures in January 2023. The Company’s $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, andRCF expired 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.2019. At December 31, 2015, the Company2018, Anadarko had no outstanding borrowings under the Five-Year FacilityAPC RCF or the 364-Day Facility and was in compliance with all covenants therein.covenants.
WES RCF During 2015, WES borrowings were primarily used for general partnership purposes, including the fundinghas a $1.5 billion senior unsecured RCF which is expandable to a maximum of capital expenditures.$2.0 billion that matures in February 2023. At December 31, 2015,2018, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $300$220 million, at an interest rate of 1.73%, had outstanding letters of credit of $6$5 million, and had available borrowing capacity of $894 million.$1.3 billion, and was in compliance with all covenants.
During 2014,February 2024 effective on February 15, 2019 and to expand the borrowing capacity to $2.0 billion, while leaving the $500 million accordion feature unexercised. Expansion of the borrowing capacity is subject to the completion of the 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 locatedMerger anticipated in the Marcellus shale in north-central Pennsylvania and an intrastate pipeline in southwestern Wyoming, and for other general partnership purposes, including the fundingfirst quarter of capital expenditures.
For additional information on the Company’s revolving credit facilities, such as years of maturity, interest rates, and covenants, see2019. See Note 11—Debt and Interest Expense24—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.10-K for additional information related to the WES Merger.
WGP RCF WGP has a $35 million senior secured RCF that matures the earlier of June 2019 or three business days following the completion of the WES Merger. At December 31, 2018, WGP had outstanding borrowings under its RCF of $28 million classified as short-term debt on the Company’s Consolidated Balance Sheet, available borrowing capacity of $7 million, and was in compliance with all covenants. See Note 24—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information related to the WES Merger.
Commercial Paper ProgramIn January 2015, theThe Company initiatedhas a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper notes and is supported bynotes. As a result of Moody’s credit rating on Anadarko, 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 inaccess to 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, maximumhas been limited. There were no outstanding borrowings under the commercial paper program were $1.4 billionat December 31, 2018.
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES | |
Debt Activity Amounts in the table below do not include capital lease activity and the average borrowings outstanding were $773 million with a weighted-average interest rate of 0.57%. are presented at face value.
|
| | | | | | | | | | | | | |
| millions | Company | 2018 |
| | 2017 |
| | 2016 |
| Description |
| Issuances | Anadarko | $ | — |
| | $ | — |
| | $ | 800 |
| 4.850% Senior Notes due 2021 (1) |
| | Anadarko | — |
| | — |
| | 1,100 |
| 5.550% Senior Notes due 2026 (1) |
| | Anadarko | — |
| | — |
| | 1,100 |
| 6.600% Senior Notes due 2046 (1) |
| | WES | 400 |
| | — |
| | — |
| WES 4.500% Senior Notes due 2028 (2) |
| | WES | 700 |
| | — |
| | — |
| WES 5.300% Senior Notes due 2048 (2) |
| | WES | 400 |
| | — |
| | — |
| WES 4.750% Senior Notes due 2028 (3) |
| | WES | 350 |
| | — |
| | — |
| WES 5.500% Senior Notes due 2048 (3) |
| | WES | — |
| | — |
| | 500 |
| WES 4.650% Senior Notes due 2026 (4) |
| | WES | — |
| | — |
| | 200 |
| WES 5.450% Senior Notes due 2044 (2) |
| Borrowings | Anadarko | — |
| | — |
| | 1,750 |
| 364-Day Facility (5) |
| | WES | 540 |
| | 370 |
| | 600 |
| WES RCF (6) |
| | WGP | — |
| | — |
| | 28 |
| WGP RCF |
| Repayments | Anadarko | (114 | ) | | — |
| | — |
| 7.050% Debentures due 2018 |
| | Anadarko | (123 | ) | | — |
| | — |
| 4.850% Senior Notes due 2021 (7) |
| | Anadarko | (377 | ) | | — |
| | — |
| 3.450% Senior Notes due 2024 (7) |
| | Anadarko | (90 | ) | | — |
| | — |
| Zero Coupon Notes due 2036 |
| | Anadarko | — |
| | (6 | ) | | — |
| 7.000% Debentures due 2027 |
| | Anadarko | — |
| | (3 | ) | | — |
| 6.625% Debentures due 2028 |
| | Anadarko | — |
| | (1 | ) | | — |
| 7.950% Debentures due 2029 |
| | Anadarko | — |
| | — |
| | (1,750 | ) | 5.950% Senior Notes due 2016 (8) |
| | Anadarko | — |
| | — |
| | (2,000 | ) | 6.375% Senior Notes due 2017 (8) |
| | Anadarko | — |
| | — |
| | (1,750 | ) | 364-Day Facility |
| | Anadarko | — |
| | — |
| | (250 | ) | Commercial paper notes, net |
| | Anadarko | (17 | ) | | (34 | ) | | (34 | ) | TEUs - senior amortizing notes |
| | WES | (350 | ) | | — |
| | — |
| WES 2.600% Senior Notes due 2018 |
| | WES | (690 | ) | | — |
| | (900 | ) | WES RCF |
| |
(1) | Proceeds were used to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016. |
| |
(2) | Proceeds were used to repay amounts outstanding under the WES RCF, with remaining proceeds used for general partnership purposes, including capital expenditures. |
| |
(3) | Proceeds were used to repay the maturing $350 million 2.600% Senior Notes due August 2018 and amounts outstanding under the WES RCF, with remaining proceeds used for general partnership purposes, including capital expenditures. |
| |
(4) | Proceeds were used to repay a portion of the amount outstanding under the WES RCF. |
| |
(5) | Proceeds were primarily used for general short-term working capital needs. |
| |
(6) | Borrowings in 2018 and 2017 were used for general partnership purposes, including capital expenditures. In 2016, borrowings were used to fund a portion of an acquisition and for general partnership purposes, including capital expenditures. |
| |
(7) | The Company purchased and retired $377 million of its $625 million 3.450% Senior Notes due 2024 and $123 million of its $800 million 4.850% Senior Notes due 2021 pursuant to a tender offer. |
| |
(8) | The Company recognized losses of $155 million for the early retirement and redemption of these senior notes, which included $144 million of premiums paid. |
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES | |
Debt Maturities At December 31, 2015, Anadarko’s scheduled debt maturities during 2016 consisted2018, Anadarko had outstanding borrowings of $1.750 billion 5.950%$600 million of 8.700% Senior Notes scheduled to mature in September, $250due March 2019 and $300 million of borrowings under6.950% Senior Notes due June 2019 classified as short-term debt on the commercial paper program,Company’s Consolidated Balance Sheet. The Company plans to retire this debt at maturity.
In December 2018, the Company purchased and $33retired $36 million of the accreted value of its Zero Coupons due 2036, which resulted in a reduction of $90 million of the $2.4 billion originally due at maturity in 2036. The principal payments related to the senior amortizing notes associated withZero Coupons are reported in financing activities and interest accretion payments related to the TEUs.Zero Coupons are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons)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 atof the next put date in October 2016.
The Company classified the 5.950% Senior Notes,outstanding Zero Coupons. None of the Zero Coupons andwere put to the outstanding commercial paper notesCompany in October 2018. The Zero Coupons can next be put to the Company in October 2019, which, if put in whole, would be $942 million. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at December 31, 2015,2018, as Anadarko intendsthe Company has the ability and intent to refinance these obligations prior to or at maturity with newusing 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 mayshould a put be material.exercised.
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—13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Tangible Capital Lease Obligations Construction of the FPSO for the Company’s TEN field operations in Ghana commenced in 2013. The Company recognized an asset and related obligation during the construction period for its pro-rata share. Upon completion of the construction during the third quarter of 2016, the Company reported the asset and related obligation as a capital lease of $225 million for the Company’s share of the fair value of the FPSO based on the operator’s lease agreement. The Company made capital lease payments of $46 million in 2018 and $44 million in 2017. Anadarko’s scheduled payments for 2019 associated with capital lease obligations are $58 million. Principal payments related to capital lease obligations are reported in financing activities and interest payments related to capital lease obligations are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. See Note 13—Debt and Interest ExpenseintheNotestoConsolidatedFinancialStatementsunderItem8ofthisForm 10-K for additional information.
Equity UnitsTransactions During 2015, Anadarko issued 9.22018, as part of the Share-Repurchase Program, the Company completed the repurchase of 43.1 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’sits common stock in lieufor $2.7 billion under two ASR Agreements and through open-market repurchases. During 2017, the Company completed the repurchase of WGP21.9 million shares of its common units,stock for $1.1 billion under an ASR Agreement and a senior amortizing note due in June 2018, which bears interest at the rate of 1.50% per year.through open-market repurchases. For additional information, see Note 10—Tangible21—Stockholders’ Equity Units in theNotes to Consolidated Financial Statements under Item 8 of this Form 10-K. During 2015,10‑K. In September 2016, Anadarko repaid $16completed a public offering of 40.5 million shares of its common stock for net proceeds of $2.16 billion. Net proceeds were primarily used to fund the GOM Acquisition, with the remainder used for general corporate purposes.
Anadarko sold 12.5 million of senior amortizing notes associated withits WGP common units to the TEUs.
Tablepublic for net proceeds of Contents$476 million in 2016. The proceeds were used for general corporate purposes. At December 31, 2018, Anadarko owned 170 million WGP common units, which represents a 77.8% interest in WGP.
Derivative InstrumentsInterest-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 derivative instruments are subjectexisting or anticipated exposure 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 settlementinterest-rate changes. The fair value 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 declinescurrent interest-rate swap portfolio is subject to a level that is below investment grade. Derivativechanges in interest rates. Net cash payments related to settlements and collateralization are classified asamendments of interest-rate swap agreements were $92 million in 2018, $112 million in 2017, and $274 million in 2016. For information on derivative instruments, including 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,flow treatment, see Note 9—11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Conveyance of Future Hard-Minerals Royalty RevenuesDuring the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. The Company made payments for royalties of $50 million in both 2018 and 2017, and $25 million in 2016. For additional information on the cash flow treatment, expected timing, and scheduled payments of the conveyed royalties, see Note 16—Conveyance of Future Hard-Minerals Royalty Revenues in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES | |
Common Stock DividendsAnadarko paid dividends to its common stockholders of $553$528 million in 2015, $5052018, $111 million in 2014,2017, and $274$105 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 2014.2016. In response to the current commodity-price environment,a sustained decline in commodity prices, the Company decreased the quarterly dividend from $0.27 per share to $0.05 per share in February 2016. In February 2018, the Company increased the quarterly dividend to $0.25 per share. As part of the Company’s focus on increasing shareholder returns, the quarterly dividend was increased again in November 2018 to $0.30 per share. 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 the Company’s earnings, financial conditions,condition, 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 OwnersWES distributedDistributions 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 distributionsnoncontrolling interest owners primarily relate 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).following:
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) |
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
WES distributions to unitholders (excluding Anadarko and WGP) (1) | $ | 379 |
| | $ | 326 |
| | $ | 258 |
|
WES distributions to Series A Preferred unitholders (2) | — |
| | 22 |
| | 31 |
|
| WES distributions to Chipeta noncontrolling interest owners | 14 |
| | 14 |
| | 14 |
|
WGP distributions to unitholders (excluding Anadarko) (3) | 102 |
| | 81 |
| | 59 |
|
| |
(1) | WES has made quarterly distributions to its unitholders since its 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 $0.98 per common unit for the fourth quarter of 2018 (paid in February 2019). |
| |
(2) | WES made distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders since the unit issuances in March and April 2016. As of June 30, 2017, all Series A Preferred units had converted into WES common units. See Note 24—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
| |
(3) | 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 $0.6025 per unit for the fourth quarter of 2018 (to be paid in February 2019). |
73APC 2018 FORM 10-K | 79
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES | |
Insurance Coverage and Other Indemnities
|
|
| 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$1.2 billion 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$500 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 80 | APC 2018 FORM 10-K
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES | |
|
|
| 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.
The following is a summary of the Company’s obligations at December 31, 2015:2018:
|
| | | | | | | | | | | | | | | | | | | |
| | 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 |
|
_______________________________________________________________________________ |
| | | | | | | | | | | | | | | | | | | | | |
| | | | Obligations by Period |
| millions | Note Reference (1) | 2019 | | 2020-2021 | | 2022-2023 | | Thereafter | | Total | |
| Total debt | | | | | | | | | | | |
Principal—total borrowings (2) | | | $ | 928 |
| | $ | 1,177 |
| | $ | 890 |
| | $ | 14,666 |
| | $ | 17,661 |
|
| Interest on borrowings | | | 834 |
| | 1,655 |
| | 1,530 |
| | 9,515 |
| | 13,534 |
|
| Capital lease obligation and interest | | | 58 |
| | 98 |
| | 88 |
| | 323 |
| | 567 |
|
Investee entities’ debt and interest (3) | | | 108 |
| | 206 |
| | 204 |
| | 2,115 |
| | 2,633 |
|
| Operating leases | | | 264 |
| | 196 |
| | 59 |
| | 135 |
| | 654 |
|
Oil and gas activities (4) | | | 272 |
| | 332 |
| | 109 |
| | 89 |
| | 802 |
|
| Midstream and marketing activities | | | 875 |
| | 1,816 |
| | 1,323 |
| | 1,409 |
| | 5,423 |
|
| AROs | | | 254 |
| | 345 |
| | 699 |
| | 1,801 |
| | 3,099 |
|
Derivative liabilities (5) | | | 72 |
| | 655 |
| | 448 |
| | — |
| | 1,175 |
|
Uncertain tax positions (6) | | | 70 |
| | 74 |
| | 1,143 |
| | — |
| | 1,287 |
|
| Environmental liabilities | | | 22 |
| | 35 |
| | 10 |
| | 42 |
| | 109 |
|
| Other | | | 20 |
| | 200 |
| | 31 |
| | 57 |
| | 308 |
|
Total (7) | | | $ | 3,777 |
| | $ | 6,789 |
| | $ | 6,534 |
| | $ | 30,152 |
| | $ | 47,252 |
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(2) | Includes the fully accreted principal amount of the Zero Coupons of approximately $2.4$2.3 billion as coming due after 2020.2023. 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 $839for $942 million, if put in whole, in October 20162019 (the next potential put date). |
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(3) | Anadarko has legal right of setoffThe obligations 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, therelated investments and the obligations are presented net on the Company’s Consolidated Balance Sheets in other assets or other long-term liabilities—other for all periods presented. These notes payable provide for a variable rate of interest, reset quarterly. Therefore, futureliabilities-other. Future interest payments presented in the table above are estimated using the relevant forward LIBOR rate curve. Further, the above table does not reflect theThe preferred return that Anadarko receives on its investment in these entities which is also LIBOR-based, butnot included.
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(4) | Includes long-term drilling and work-related commitments of $802 million, comprised of approximately $670 million related to the United States and $132 million related to international locations. Amounts are undiscounted and do not include purchase commitments for jointly owned fields and facilities where the Company is not the operator. |
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(5) | Represents Anadarko’s gross derivative liability after taking into account the impacts of netting margin and collateral balances deposited with a lower margin thancounterparties. |
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(6) | Timing of conclusion of the margin onuncertain tax positions cannot be determined with certainty. |
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(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.MANAGEMENT’S DISCUSSION AND ANALYSIS |
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(5)
| See Note 12—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
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.
CRITICAL ACCOUNTING ESTIMATES
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| CRITICAL ACCOUNTING ESTIMATES |
The preparation of financial statements in accordance with generally accepted accounting principles in the United States (GAAP)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.
MethodologyAnadarko estimates its proved oil and gas reserves according to the definition of proved reserves provided by the Securities and Exchange CommissionSEC and the Financial Accounting Standards Board.FASB. 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.
Judgments and uncertainties Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. 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 volumesvolume 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-productionUOP calculations had been lower by five percent10% across all properties, DD&A in 20152018 would have increased by approximately $223$390 million.
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| MANAGEMENT’S DISCUSSION AND ANALYSIS CRITICAL ACCOUNTING ESTIMATES | |
MethodologyUnder the successful efforts method of accounting, exploratory drilling costs associated with a well discovering hydrocarbons are initially capitalized or suspended, pending athe determination as to whether a commercially sufficient quantity of proved reserves. If proved reserves canare found, drilling costs remain capitalized and are classified as proved properties. For exploratory wells that find reserves that cannot be attributedclassified as proved when drilling is completed, costs continue to the areabe capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a resultproducing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of drilling.the project. 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.
Judgments and uncertainties Significant management judgment is required to determine whether sufficient progress has been made in assessing the reserves and the economic and operating viability of the project to continue capitalization of the exploratory drilling costs. In making this determination all relevant facts and circumstances shall be evaluated, and no single indicator is determinative. Relevant facts and circumstances include, but are not limited to, commitment of project personnel, costs being incurred to assess the reserves and their potential development, assessment in progress covering the economic, legal, political, and environmental aspects of the potential development, and the existence or active negotiations of agreements with governments or sales contracts with customers. The determination of proved reserves 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.
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—7—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information.
MethodologyThe 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.
Judgments and uncertainties 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 valuationincome 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 projectedfuture net 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
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| MANAGEMENT’S DISCUSSION AND ANALYSIS CRITICAL ACCOUNTING ESTIMATES | |
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| Impairments of Proved Oil and Natural-Gas Properties |
Methodology Proved oil and natural-gas properties are assessed for impairment when facts and circumstances indicate that net book values may not be recoverable. When impairment indicators are present, an undiscounted future net 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, the property’s fair value is estimated and an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value.
Judgments and uncertainties The primary assumptions used to estimate undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs. In most cases, the assumption that generates the most variability in undiscounted future net cash flows is future commodity prices. For impairment testing, the Company used the five-year forward strip prices for oil and natural gas, with prices subsequent to the fifth year held constant as the benchmark price in the undiscounted future net cash flows. Capital and operating costs were estimated assuming no escalation for years where the average oil strip price was below $50 per Bbl and 1% escalation for the years where the average oil strip price exceeded $50 per Bbl and held constant thereafter.
Due to the volatility of crude oil, natural gas, and NGL prices, these cash flow estimates are inherently imprecise. Unfavorable changes in any of the primary assumptions could result in a reduction in undiscounted future cash flows and could indicate property impairment. Uncertainties related to the primary assumptions could affect the timing of an impairment.
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| Impairments of Unproved Oil and Natural-Gas Properties |
Methodology Acquisition costs of unproved oil and natural-gas properties are periodically assessed for impairment and are transferred to proved oil and gas properties may beto the extent the costs are associated with successful exploration activities. The Company has classified unproved oil and natural-gas properties into three categories: significant, significant where probable and possible reserves estimations are available, and individually insignificant. Significant undeveloped leases are assessed individually for impairment and a valuation allowance is provided if impairment is indicated. In situations where fair values have been allocated to a significant unproved property based on estimations of probable and possible reserves as the result of a business combination or other purchase of proved and unproved properties, an undiscounted future net cash flow analysis is used to assess the property for impairment in addition to consideration of reserves volume needed to transfer the balance of unproved property to proved property. 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.
Judgments and uncertainties In determining whether a significant unproved property is impaired numerous factors are considered including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the expectedproperty being evaluated and/or adjacent properties, geologists’ evaluation of the property, and the remaining months in the lease term for the property. In situations where probable and possible reserves are available, undiscounted future net cash flows used in the impairment analysis are determined based upon management’s estimates of probable and possible reserves, future commodity prices, and future costs to produce the asset group are compared to the carrying amount of the asset.reserves. 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 lowerless 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 inproperty, indicating impairment, 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 asflows are discounted and compared to the excesscarrying value for determining the amount of an asset’s carrying amount over its estimated fair value.the impairment loss to record. The Company uses a variety of fair-value measurement techniques asutilizes the same pricing and cost assumptions discussed above when market informationin Impairments of Proved Oil and Natural-Gas Properties. Uncertainties related to the primary assumptions or unfavorable revisions in estimated reserves quantities could cause a reduction in the value of a property and therefore indicate an impairment. Management’s assessment of the results of exploration activities, availability of funds for future activities, and the same or similar assets does not exist.current and projected political and regulatory climate in areas in which the Company operates also impact the amounts and timing of impairment provisions.
Goodwill Impairments
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| MANAGEMENT’S DISCUSSION AND ANALYSIS CRITICAL ACCOUNTING ESTIMATES | |
MethodologyThe Company tests goodwill for impairment annuallyis subject to income taxes in October (or more frequently as circumstances dictate).numerous taxing jurisdictions worldwide. 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 first assesses whether an impairment of goodwill is indicated throughhas recognized deferred tax assets and liabilities for temporary differences, operating losses, and tax-credit carryforwards.
The deferred tax assets may be reduced by 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 concludesvaluation allowance if it is more likely than not that fair valuesome portion or all of the reporting unit exceedsdeferred tax assets will not be realized. The Company routinely assesses the related carrying amount, then goodwill is not impairedrealizability of its deferred tax assets by analyzing the reversal periods of available net operating loss carryforwards and further testing is not necessary. Ifcredit carryforwards, temporary differences in tax assets and liabilities, the qualitative assessment indicates fair valueavailability of the reporting unit may be less than its carrying amount, thetax planning strategies, and estimates of future taxable income and other factors.
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,also routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts, including goodwill, and determines whether impairment is necessary.
When evaluating whetherinterest where appropriate. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the fair valueposition will be sustained upon examination, based on the technical merits of a reporting unit is less than its carrying amount, the Company assesses relevant eventsposition.
Judgments and circumstances,uncertainties The accruals for deferred tax assets and liabilities, including the following:
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. The assessment of potential uncertain tax positions requires a significant amount of judgment and are reviewed and adjusted on a periodic basis, taking into consideration the stock priceprogress of Anadarko, WES,ongoing tax audits, case law, and WGP
new legislation. Although management considers its tax accruals adequate, material changes in commodity prices
these accruals may occur in the future based on the progress of ongoing tax audits, changes in cost factors such as costslegislation, and resolution of drilling; production costs;pending tax matters. Additionally, numerous judgments and gathering, processing,assumptions are inherent in management’s estimates of future taxable income used to assess the realizability of certain deferred tax assets. The estimates used are based on assumptions of proved oil and other transportation costs
impairments recognized by the Company
acquisitions and disposals of assets
changes to the Company’sgas reserves, including changes due to fluctuations in commodity prices, and updates todevelopment assumptions that are consistent with the Company’s plans or forecasts
changes in trading multiples for midstream peersinternal business plans.
Because quoted market prices
Methodology The Company is subject to various legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, the Company accrues losses 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. The Company’s in-house legal counsel 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 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 EBITDAliability 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.contingencies.
Environmental ObligationsJudgments and Other Contingencies
uncertaintiesManagement 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.
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. |
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| RECENT ACCOUNTING DEVELOPMENTS |
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| MARKET RISK QUANTITATIVE AND QUALITATIVE DISCLOSURES | |
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—11—Derivative Instruments in theNotestoConsolidatedFinancialStatementsunderItem8ofthisForm10-K.
The Company’s most significant market risk relates to prices for oil, 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 3032 MMBbls of oil 14 Bcf of natural gas, and 1 MMBbls of NGLs at December 31, 2015,2018, with a net derivative asset position of $273$171 million. Based on actual derivative contractual volumes,volume, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $58$67 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $44$56 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.
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,activities, seeMarketing Activities under Items 1 and 2 of this Form 10-K.
Borrowings, if any, under each of the 364-Day Facility, the Five-YearAPC RCF, the WES RCF, the WES 364-Day Facility, and the commercial paper program, and WES’sWGP RCF are subject to variable interest rates. The remaining balance of Anadarko’s short-term and long-term debt on the Company’s Consolidated Balance Sheetsborrowings has fixed interest rates. The Company has $2.9 billion of LIBOR-based 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-controllednoncontrolled 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 LIBORthe applicable benchmark interest rate would not materially impact the Company’s interest cost, it would affect the fair value of outstanding fixed-rate debt.
At December 31, 2015,2018, the Company had a net derivative liability position of $1.5$1.2 billion related to interest-rate swaps. A 10% increase (decrease) in the three-month LIBOR interest-rate curve would increase (decrease)decrease (increase) the aggregate fair value of outstanding interest-rate swap agreements by $103$92 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—11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
FOREIGN-CURRENCY EXCHANGE-RATE RISK86 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| APC in the 2018 FORM 10-KNotes 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.
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| FINANCIAL STATEMENTS INDEX | |
Item 8. Financial Statements and Supplementary Data
ANADARKO PETROLEUM CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS |
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| INDEX TO CONSOLIDATED FINANCIAL STATEMENTS | Page |
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82APC 2018 FORM 10-K | 87
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| FINANCIAL STATEMENTS REPORTS | |
ANADARKO PETROLEUM CORPORATION
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.
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| 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 reliability of financial reporting and the preparation and fair presentation of published financial statements.statements for external purposes in accordance with generally accepted accounting principles.
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, 2015.2018. This assessment was based on criteria established in the Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (COSO).Commission. 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.as of December 31, 2018.
KPMG LLP has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2015.2018.
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| /s/ R. A. WALKER |
R. A. Walker Chairman President and Chief Executive Officer |
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/s/ ROBERT G. GWINBENJAMIN M. FINK |
Robert G. GwinBenjamin M. Fink
Executive Vice President, Finance and Chief Financial Officer |
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February 17, 201614, 2019 |
8388 | APC 2018 FORM 10-K
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| FINANCIAL STATEMENTS REPORTS | |
Report of Independent Registered Public Accounting Firm
TheTo the Stockholders and Board of Directors and Stockholders
Anadarko Petroleum Corporation:
Opinion on Internal Control Over Financial Reporting
We have audited Anadarko Petroleum Corporation’sCorporation and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2015,2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in .Internal Control - Integrated Framework (2013) Anadarko Petroleum Corporation’sissued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 and 2017, 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, 2018, and the related notes (collectively, the consolidated financial statements), and our report dated February 14, 2019 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’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 Report of Management – Management’s Assessment of Internal Control overOver Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. 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 of internal control over financial reporting 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.
Definition and Limitations of Internal Control Over Financial Reporting
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.
|
|
| /s/ KPMG LLP |
|
| Houston, Texas |
| February 14, 2019 |
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 inAPC Internal Control2018 FORM 10-K –| Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).89
|
| | |
| FINANCIAL STATEMENTS REPORTS | |
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Anadarko Petroleum Corporation:
Opinion on the Consolidated Financial Statements
We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), theaccompanying consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries (the Company) as of December 31, 20152018 and 2014, and2017, 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, 2015,2018, and our report dated February 17, 2016 expressed an unqualified opinion on thosethe related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements.
|
|
/s/ KPMG LLP |
|
Houston, Texas |
February 17, 2016 |
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 subsidiariesCompany as of December 31, 20152018 and 2014,2017, and the related consolidated statementsresults of income, comprehensive income, equity,its operations and its 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, 2015,2018, 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) (PCAOB), Anadarko Petroleum Corporation’sthe Company’s internal control over financial reporting as of December 31, 2015,2018, 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, 201614, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for revenue recognition in 2018 due to the adoption of Accounting Standards Codification Topic 606 Revenue from Contracts with Customers.
Basis for Opinion
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 are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
|
|
| /s/ KPMG LLP |
| |
| We have served as the Company’s auditor since 1981. |
|
| Houston, Texas |
February 17, 201614, 2019 |
8590 | APC 2018 FORM 10-K
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
| | | | Years Ended December 31, | Years Ended December 31, |
| millions except per-share amounts | 2015 | | 2014 | | 2013 | 2018 |
| | 2017 |
| | 2016 |
|
| Revenues and Other | | | | | | | | | | |
| Oil and condensate sales | $ | 5,420 |
| | $ | 9,748 |
| | $ | 9,178 |
| |
| Oil sales | | $ | 9,206 |
| | $ | 6,552 |
| | $ | 4,668 |
|
| Natural-gas sales | 2,007 |
| | 3,849 |
| | 3,388 |
| 1,005 |
| | 1,348 |
| | 1,564 |
|
| Natural-gas liquids sales | 833 |
| | 1,572 |
| | 1,262 |
| 1,271 |
| | 1,069 |
| | 921 |
|
| Gathering, processing, and marketing sales | 1,226 |
| | 1,206 |
| | 1,039 |
| 1,588 |
| | 2,000 |
| | 1,294 |
|
| Gains (losses) on divestitures and other, net | (788 | ) | | 2,095 |
| | (286 | ) | 312 |
| | 939 |
| | (578 | ) |
| Total | 8,698 |
| | 18,470 |
| | 14,581 |
| 13,382 |
| | 11,908 |
| | 7,869 |
|
| Costs and Expenses | | | | | | | | | | |
| Oil and gas operating | 1,014 |
| | 1,171 |
| | 1,092 |
| 1,153 |
| | 988 |
| | 807 |
|
| Oil and gas transportation | 1,117 |
| | 1,116 |
| | 981 |
| 878 |
| | 914 |
| | 1,002 |
|
| Exploration | 2,644 |
| | 1,639 |
| | 1,329 |
| 459 |
| | 2,535 |
| | 944 |
|
| Gathering, processing, and marketing | 1,054 |
| | 1,030 |
| | 869 |
| 1,047 |
| | 1,552 |
| | 1,083 |
|
| General and administrative | 1,176 |
| | 1,316 |
| | 1,090 |
| 1,084 |
| | 994 |
| | 1,223 |
|
| Depreciation, depletion, and amortization | 4,603 |
| | 4,550 |
| | 3,927 |
| 4,254 |
| | 4,279 |
| | 4,301 |
|
| Other taxes | 553 |
| | 1,244 |
| | 1,077 |
| |
| Production, property, and other taxes | | 826 |
| | 582 |
| | 536 |
|
| Impairments | 5,075 |
| | 836 |
| | 794 |
| 800 |
| | 408 |
| | 227 |
|
| Other operating expense | 271 |
| | 165 |
| | 89 |
| 262 |
| | 221 |
| | 118 |
|
| Total | 17,507 |
| | 13,067 |
| | 11,248 |
| 10,763 |
| | 12,473 |
| | 10,241 |
|
| Operating Income (Loss) | (8,809 | ) | | 5,403 |
| | 3,333 |
| 2,619 |
| | (565 | ) | | (2,372 | ) |
| Other (Income) Expense | | | | | | | | | | |
| Interest expense | 825 |
| | 772 |
| | 686 |
| 947 |
| | 932 |
| | 890 |
|
| (Gains) losses on early extinguishment of debt | | (2 | ) | | 2 |
| | 155 |
|
| (Gains) losses on derivatives, net | (99 | ) | | 197 |
| | (398 | ) | 130 |
| | 135 |
| | 286 |
|
| Other (income) expense, net | 149 |
| | 20 |
| | 89 |
| 59 |
| | 54 |
| | 126 |
|
| Tronox-related contingent loss | 5 |
| | 4,360 |
| | 850 |
| |
| Total | 880 |
| | 5,349 |
| | 1,227 |
| 1,134 |
| | 1,123 |
| | 1,457 |
|
| Income (Loss) Before Income Taxes | (9,689 | ) | | 54 |
| | 2,106 |
| 1,485 |
| | (1,688 | ) | | (3,829 | ) |
| Income tax expense (benefit) | (2,877 | ) | | 1,617 |
| | 1,165 |
| 733 |
| | (1,477 | ) | | (1,021 | ) |
| Net Income (Loss) | (6,812 | ) | | (1,563 | ) | | 941 |
| 752 |
| | (211 | ) | | (2,808 | ) |
| Net income (loss) attributable to noncontrolling interests | (120 | ) | | 187 |
| | 140 |
| 137 |
| | 245 |
| | 263 |
|
| Net Income (Loss) Attributable to Common Stockholders | $ | (6,692 | ) | | $ | (1,750 | ) | | $ | 801 |
| $ | 615 |
| | $ | (456 | ) | | $ | (3,071 | ) |
| | | | | | | | | | | |
| Per Common Share | | | | | | | | | | |
| Net income (loss) attributable to common stockholders—basic | $ | (13.18 | ) | | $ | (3.47 | ) | | $ | 1.58 |
| $ | 1.20 |
| | $ | (0.85 | ) | | $ | (5.90 | ) |
| Net income (loss) attributable to common stockholders—diluted | $ | (13.18 | ) | | $ | (3.47 | ) | | $ | 1.58 |
| $ | 1.20 |
| | $ | (0.85 | ) | | $ | (5.90 | ) |
| Average Number of Common Shares Outstanding—Basic | 508 |
| | 506 |
| | 502 |
| 504 |
| | 548 |
| | 522 |
|
| Average Number of Common Shares Outstanding—Diluted | 508 |
| | 506 |
| | 505 |
| 504 |
| | 548 |
| | 522 |
|
| 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, | Years Ended December 31, |
| millions | 2015 | | 2014 | | 2013 | 2018 |
| | 2017 |
| | 2016 |
|
| Net Income (Loss) | $ | (6,812 | ) | | $ | (1,563 | ) | | $ | 941 |
| $ | 752 |
| | $ | (211 | ) | | $ | (2,808 | ) |
| Other Comprehensive Income (Loss) | | | | | | | | | | |
| Adjustments for derivative instruments | | | | | | | | | | |
Cumulative effect of accounting change (1) | | (7 | ) | | — |
| | — |
|
| Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | 10 |
| | 9 |
| | 11 |
| 3 |
| | 3 |
| | 8 |
|
| Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | (4 | ) | | (3 | ) | | (4 | ) | (1 | ) | | (1 | ) | | (3 | ) |
| Total adjustments for derivative instruments, net of taxes | 6 |
| | 6 |
| | 7 |
| (5 | ) | | 2 |
| | 5 |
|
| Adjustments for pension and other postretirement plans | | | | | | | | | | |
Cumulative effect of accounting change (1) | | (66 | ) | | — |
| | — |
|
| Net gain (loss) incurred during period | 49 |
| | (405 | ) | | 416 |
| 50 |
| | (14 | ) | | (175 | ) |
| Income taxes on net gain (loss) incurred during period | (18 | ) | | 149 |
| | (152 | ) | (11 | ) | | 4 |
| | 68 |
|
| 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 |
| | — |
| | — |
| |
| Amortization of net actuarial (gain) loss to other (income) expense, net | | 74 |
| | 116 |
| | 188 |
|
| Income taxes on amortization of net actuarial (gain) loss | | (20 | ) | | (40 | ) | | (73 | ) |
| Amortization of net prior service (credit) cost to other (income) expense, net | | (24 | ) | | (25 | ) | | (34 | ) |
| Income taxes on amortization of net prior service (credit) cost | | 5 |
| | 10 |
| | 13 |
|
| Total adjustments for pension and other postretirement plans, net of taxes | 128 |
| | (238 | ) | | 348 |
| 8 |
| | 51 |
| | (13 | ) |
| Total | 134 |
| | (232 | ) | | 355 |
| 3 |
| | 53 |
| | (8 | ) |
| Comprehensive Income (Loss) | (6,678 | ) | | (1,795 | ) | | 1,296 |
| 755 |
| | (158 | ) | | (2,816 | ) |
| Comprehensive income (loss) attributable to noncontrolling interests | (120 | ) | | 187 |
| | 140 |
| 137 |
| | 245 |
| | 263 |
|
| Comprehensive Income (Loss) Attributable to Common Stockholders | $ | (6,558 | ) | | $ | (1,982 | ) | | $ | 1,156 |
| $ | 618 |
| | $ | (403 | ) | | $ | (3,079 | ) |
| |
(1) | Beginning January 1, 2018, the Company adopted ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information. |
See accompanying Notes to Consolidated Financial Statements.
87
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
| | | | December 31, | December 31, |
| millions | 2015 | | 2014 | |
| millions except per-share amounts | | 2018 |
| | 2017 |
|
| 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 |
| |
| Cash and cash equivalents ($92 and $80 related to VIEs) | | $ | 1,295 |
| | $ | 4,553 |
|
| Accounts receivable (net of allowance of $13 and $14) | | | | |
| Customers ($138 and $106 related to VIEs) | | 1,491 |
| | 1,222 |
|
| Others ($15 and $19 related to VIEs) | | 535 |
| | 607 |
|
| Other current assets | 574 |
| | 603 |
| 474 |
| | 380 |
|
| Total | 3,982 |
| | 10,499 |
| 3,795 |
| | 6,762 |
|
| 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 |
| |
Net properties and equipment (net of accumulated depreciation, depletion, and amortization of $37,905 and $34,107) ($6,612 and $5,731 related to VIEs) | | 28,615 |
| | 27,451 |
|
Other Assets ($868 and $579 related to VIEs) | | 2,336 |
| | 2,211 |
|
Goodwill and Other Intangible Assets ($1,163 and $1,191 related to VIEs) | | 5,630 |
| | 5,662 |
|
| Total Assets | $ | 46,414 |
| | $ | 60,967 |
| $ | 40,376 |
| | $ | 42,086 |
|
| | | | | | | |
| LIABILITIES AND EQUITY | | | | | | |
| Current Liabilities | | | | | | |
| Accounts payable | $ | 2,850 |
| | $ | 3,683 |
| | | |
| Trade ($263 and $305 related to VIEs) | | $ | 2,003 |
| | $ | 1,894 |
|
| Other ($15 and $1 related to VIEs) | | 161 |
| | 266 |
|
Short-term debt - Anadarko (1) | | 919 |
| | 142 |
|
| Short-term debt - WES and WGP | | 28 |
| | — |
|
| Current asset retirement obligations | 309 |
| | 257 |
| 252 |
| | 294 |
|
| Interest payable | 247 |
| | 247 |
| |
| Other taxes payable | 318 |
| | 332 |
| |
| Accrued expenses | 424 |
| | 505 |
| |
| Short-term debt | 33 |
| | — |
| |
| Tronox-related contingent liability | — |
| | 5,210 |
| |
| Other current liabilities | | 1,295 |
| | 1,310 |
|
| Total | 4,181 |
| | 10,234 |
| 4,658 |
| | 3,906 |
|
| Long-term Debt | 15,718 |
| | 15,092 |
| | | |
Long-term debt - Anadarko (1) | | 10,683 |
| | 12,054 |
|
| Long-term debt - WES and WGP | | 4,787 |
| | 3,493 |
|
| Total | | 15,470 |
| | 15,547 |
|
| Other Long-term Liabilities | | | | | | |
| Deferred income taxes | 5,400 |
| | 8,527 |
| 2,437 |
| | 2,234 |
|
| Asset retirement obligations | 1,750 |
| | 1,796 |
| |
| Asset retirement obligations ($260 and $143 related to VIEs) | | 2,847 |
| | 2,500 |
|
| Other | 3,908 |
| | 3,000 |
| 4,021 |
| | 4,109 |
|
| Total | 11,058 |
| | 13,323 |
| 9,305 |
| | 8,843 |
|
| | | | | | | |
| 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 |
| |
| Common stock, par value $0.10 per share (1.0 billion shares authorized, 576.6 million and 574.2 million shares issued) | | 57 |
| | 57 |
|
| Paid-in capital | 9,265 |
| | 9,005 |
| 12,393 |
| | 12,000 |
|
| Retained earnings | 4,880 |
| | 12,125 |
| 1,245 |
| | 1,109 |
|
| Treasury stock (20.0 million and 19.3 million shares) | (995 | ) | | (940 | ) | |
| Treasury stock (87.2 million and 43.4 million shares) | | (4,864 | ) | | (2,132 | ) |
| Accumulated other comprehensive income (loss) | (383 | ) | | (517 | ) | (335 | ) | | (338 | ) |
| Total Stockholders’ Equity | 12,819 |
| | 19,725 |
| 8,496 |
| | 10,696 |
|
| Noncontrolling interests | 2,638 |
| | 2,593 |
| 2,447 |
| | 3,094 |
|
| Total Equity | 15,457 |
| | 22,318 |
| 10,943 |
| | 13,790 |
|
| Total Liabilities and Equity | $ | 46,414 |
| | $ | 60,967 |
| $ | 40,376 |
| | $ | 42,086 |
|
Parenthetical references reflect amounts as of December 31, 2018, and December 31, 2017.
See accompanying Notes to Consolidated Financial Statements.
88
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
| | | | Total Stockholders’ Equity | | | | | Total Stockholders’ Equity | | |
| millions | Common Stock | | Paid-in Capital | | Retained Earnings | | Treasury Stock | | Accumulated Other Comprehensive Income (Loss) | | Non- controlling Interests | | Total Equity | 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 |
| |
| Balance at December 31, 2015 | | $ | 52 |
| $ | 9,265 |
| $ | 4,880 |
| $ | (995 | ) | | $ | (383 | ) | | $ | 2,638 |
| $ | 15,457 |
|
| Net income (loss) | — |
| | — |
| | 801 |
| | — |
| | — |
| | 140 |
| | 941 |
| — |
| — |
| (3,071 | ) | — |
| | — |
| | 263 |
| (2,808 | ) |
| Common stock issued | 1 |
| | 292 |
| | — |
| | — |
| | — |
| | — |
| | 293 |
| 5 |
| 2,150 |
| — |
| — |
| | — |
| | — |
| 2,155 |
|
| Share-based compensation expense | | — |
| 197 |
| — |
| — |
| | — |
| | — |
| 197 |
|
| Dividends—common stock | — |
| | — |
| | (274 | ) | | — |
| | — |
| | — |
| | (274 | ) | — |
| — |
| (105 | ) | — |
| | — |
| | — |
| (105 | ) |
| 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 | ) | |
| Repurchases of common stock | | — |
| — |
| — |
| (38 | ) | | — |
| | — |
| (38 | ) |
| Subsidiary equity transactions | — |
| | 90 |
| | 24 |
| | — |
| | — |
| | 829 |
| | 943 |
| — |
| 263 |
| — |
| — |
| | — |
| | 746 |
| 1,009 |
|
| Distributions to noncontrolling interest owners | — |
| | — |
| | — |
| | — |
| | — |
| | (216 | ) | | (216 | ) | — |
| — |
| — |
| — |
| | — |
| | (362 | ) | (362 | ) |
| Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | — |
| | — |
| | — |
| | — |
| | 6 |
| | — |
| | 6 |
| — |
| — |
| — |
| — |
| | 5 |
| | — |
| 5 |
|
| Adjustments for pension and other postretirement plans | — |
| | — |
| | — |
| | — |
| | (238 | ) | | — |
| | (238 | ) | — |
| — |
| — |
| — |
| | (13 | ) | | — |
| (13 | ) |
| Balance at December 31, 2014 | 52 |
| | 9,005 |
| | 12,125 |
| | (940 | ) | | (517 | ) | | 2,593 |
| | 22,318 |
| |
| Balance at December 31, 2016 | | 57 |
| 11,875 |
| 1,704 |
| (1,033 | ) | | (391 | ) | | 3,285 |
| 15,497 |
|
| Net income (loss) | — |
| | — |
| | (6,692 | ) | | — |
| | — |
| | (120 | ) | | (6,812 | ) | — |
| — |
| (456 | ) | — |
| | — |
| | 245 |
| (211 | ) |
| Common stock issued | — |
| | 209 |
| | — |
| | — |
| | — |
| | — |
| | 209 |
| |
| Share-based compensation expense | | — |
| 163 |
| — |
| — |
| | — |
| | — |
| 163 |
|
| Dividends—common stock | — |
| | — |
| | (553 | ) | | — |
| | — |
| | — |
| | (553 | ) | — |
| — |
| (111 | ) | — |
| | — |
| | — |
| (111 | ) |
| Repurchase of common stock | — |
| | — |
| | — |
| | (55 | ) | | — |
| | — |
| | (55 | ) | |
| Repurchases of common stock | | — |
| — |
| — |
| (1,099 | ) | | — |
| | — |
| (1,099 | ) |
| Subsidiary equity transactions | — |
| | 51 |
| | — |
| | — |
| | — |
| | 99 |
| | 150 |
| — |
| (35 | ) | — |
| — |
| | — |
| | 9 |
| (26 | ) |
| Issuance of tangible equity units | — |
| | — |
| | — |
| | — |
| | — |
| | 348 |
| | 348 |
| |
| Distributions to noncontrolling interest owners | — |
| | — |
| | — |
| | — |
| | — |
| | (282 | ) | | (282 | ) | — |
| — |
| — |
| — |
| | — |
| | (445 | ) | (445 | ) |
| Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | — |
| | — |
| | — |
| | — |
| | 6 |
| | — |
| | 6 |
| — |
| — |
| — |
| — |
| | 2 |
| | — |
| 2 |
|
| Adjustments for pension and other postretirement plans | — |
| | — |
| | — |
| | — |
| | 128 |
| | — |
| | 128 |
| — |
| — |
| — |
| — |
| | 51 |
| | — |
| 51 |
|
| Balance at December 31, 2015 | $ | 52 |
| | $ | 9,265 |
| | $ | 4,880 |
| | $ | (995 | ) | | $ | (383 | ) | | $ | 2,638 |
| | $ | 15,457 |
| |
| Cumulative effect of accounting change | | — |
| (3 | ) | (28 | ) | — |
| | — |
| | — |
| (31 | ) |
| Balance at December 31, 2017 | | 57 |
| 12,000 |
| 1,109 |
| (2,132 | ) | | (338 | ) | | 3,094 |
| 13,790 |
|
| Net income (loss) | | — |
| — |
| 615 |
| — |
| | — |
| | 137 |
| 752 |
|
| Common stock issued | | — |
| 7 |
| — |
| — |
| | — |
| | — |
| 7 |
|
| Share-based compensation expense | | — |
| 169 |
| — |
| — |
| | — |
| | — |
| 169 |
|
| Dividends—common stock | | — |
| — |
| (528 | ) | — |
| | — |
| | — |
| (528 | ) |
| Repurchases of common stock | | — |
| — |
| — |
| (2,732 | ) | | — |
| | — |
| (2,732 | ) |
| Subsidiary equity transactions | | — |
| (15 | ) | — |
| — |
| | — |
| | 34 |
| 19 |
|
| Settlement of tangible equity units | | — |
| 232 |
| — |
| — |
| | — |
| | (300 | ) | (68 | ) |
| Distributions to noncontrolling interest owners | | — |
| — |
| — |
| — |
| | — |
| | (495 | ) | (495 | ) |
| Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | | — |
| — |
| — |
| — |
| | 2 |
| | — |
| 2 |
|
| Adjustments for pension and other postretirement plans | | — |
| — |
| — |
| — |
| | 74 |
| | — |
| 74 |
|
Cumulative effect of accounting change(1) | | — |
| — |
| 49 |
| — |
| | (73 | ) | | (23 | ) | (47 | ) |
| Balance at December 31, 2018 | | $ | 57 |
| $ | 12,393 |
| $ | 1,245 |
| $ | (4,864 | ) | | $ | (335 | ) | | $ | 2,447 |
| $ | 10,943 |
|
| |
(1) | Beginning January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information. |
See accompanying Notes to Consolidated Financial Statements.
89
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | Years Ended December 31, | Years Ended December 31, |
| millions | 2015 | | 2014 | | 2013 | 2018 |
| | 2017 |
| | 2016 |
|
| Cash Flows from Operating Activities | | | | | | | | | | |
| Net income (loss) | $ | (6,812 | ) | | $ | (1,563 | ) | | $ | 941 |
| $ | 752 |
| | $ | (211 | ) | | $ | (2,808 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities | | | | | | |
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | | | | | | |
| Depreciation, depletion, and amortization | 4,603 |
| | 4,550 |
| | 3,927 |
| 4,254 |
| | 4,279 |
| | 4,301 |
|
| Deferred income taxes | (3,152 | ) | | (105 | ) | | 90 |
| 139 |
| | (2,169 | ) | | (1,238 | ) |
| Dry hole expense and impairments of unproved properties | 2,267 |
| | 1,245 |
| | 864 |
| 246 |
| | 2,221 |
| | 613 |
|
| Impairments | 5,075 |
| | 836 |
| | 794 |
| 800 |
| | 408 |
| | 227 |
|
| (Gains) losses on divestitures, net | 1,022 |
| | (1,891 | ) | | 470 |
| (20 | ) | | (674 | ) | | 757 |
|
| (Gains) losses on early extinguishment of debt | | (2 | ) | | 2 |
| | 155 |
|
| Total (gains) losses on derivatives, net | (100 | ) | | 207 |
| | (392 | ) | 138 |
| | 131 |
| | 292 |
|
| Operating portion of net cash received (paid) in settlement of derivative instruments | 335 |
| | 371 |
| | 85 |
| (545 | ) | | 25 |
| | 267 |
|
| Other | 320 |
| | 327 |
| | 246 |
| 294 |
| | 303 |
| | 342 |
|
| Changes in assets and liabilities | | | | | | | | | | |
| Tronox-related contingent liability | (5,210 | ) | | 4,360 |
| | 850 |
| |
| (Increase) decrease in accounts receivable | (2 | ) | | 103 |
| | 719 |
| (211 | ) | | (147 | ) | | 677 |
|
| Increase (decrease) in accounts payable and accrued expenses | (995 | ) | | 97 |
| | 148 |
| |
| Increase (decrease) in accounts payable and other current liabilities | | 348 |
| | (32 | ) | | (443 | ) |
| Other items, net | 772 |
| | (71 | ) | | 146 |
| (264 | ) | | (127 | ) | | (142 | ) |
| Net cash provided by (used in) operating activities | (1,877 | ) |
| 8,466 |
|
| 8,888 |
| 5,929 |
| | 4,009 |
| | 3,000 |
|
| Cash Flows from Investing Activities | | | | | | | | | | |
| Additions to properties and equipment and dry hole costs | (6,067 | ) | | (9,508 | ) | | (7,721 | ) | |
| Additions to properties and equipment | | (6,183 | ) | | (5,031 | ) | | (3,505 | ) |
| Acquisition of businesses | (3 | ) | | (1,527 | ) | | (473 | ) | — |
| | 25 |
| | (1,740 | ) |
| Divestitures of properties and equipment and other assets | 1,415 |
| | 4,968 |
| | 567 |
| 417 |
| | 4,008 |
| | 2,356 |
|
| Other, net | (116 | ) | | (405 | ) | | (589 | ) | (216 | ) | | (32 | ) | | 147 |
|
| Net cash provided by (used in) investing activities | (4,771 | ) |
| (6,472 | ) |
| (8,216 | ) | (5,982 | ) | | (1,030 | ) | | (2,742 | ) |
| Cash Flows from Financing Activities | | | | | | | | | | |
| Borrowings, net of issuance costs | 4,632 |
| | 2,879 |
| | 958 |
| 2,343 |
| | 369 |
| | 6,042 |
|
| Repayments of debt | (4,033 | ) | | (1,425 | ) | | (710 | ) | (1,689 | ) | | (58 | ) | | (6,832 | ) |
| Financing portion of net cash paid in settlement of derivative instruments | (35 | ) | | (222 | ) | | — |
| |
| Financing portion of net cash received (paid) for derivative instruments | | 12 |
| | (165 | ) | | (333 | ) |
| Increase (decrease) in outstanding checks | (23 | ) | | 62 |
| | (13 | ) | (39 | ) | | (43 | ) | | (103 | ) |
| Dividends paid | (553 | ) | | (505 | ) | | (274 | ) | (528 | ) | | (111 | ) | | (105 | ) |
| 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 |
| | — |
| | — |
| |
| Repurchases of common stock | | (2,732 | ) | | (1,092 | ) | | (38 | ) |
| Issuances of common stock | | 7 |
| | — |
| | 2,188 |
|
| Sales of subsidiary units | | — |
| | — |
| | 1,163 |
|
| Distributions to noncontrolling interest owners | (282 | ) | | (216 | ) | | (156 | ) | (495 | ) | | (445 | ) | | (362 | ) |
| Contributions from noncontrolling interest owners | — |
| | — |
| | 2 |
| |
| Proceeds from conveyance of future hard-minerals royalty revenues, net of transaction costs | | — |
| | — |
| | 413 |
|
| Payments of future hard-minerals royalty revenues conveyed | | (50 | ) | | (50 | ) | | (25 | ) |
| Other financing activities | | (6 | ) | | (18 | ) | | — |
|
| Net cash provided by (used in) financing activities | 220 |
|
| 1,675 |
|
| 623 |
| (3,177 | ) | | (1,613 | ) | | 2,008 |
|
| 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 |
| |
| Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents | | (15 | ) | | — |
| | 17 |
|
| Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents | | (3,245 | ) | | 1,366 |
| | 2,283 |
|
| Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at Beginning of Period | | 4,674 |
| | 3,308 |
| | 1,025 |
|
| Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at End of Period | | $ | 1,429 |
| | $ | 4,674 |
| | $ | 3,308 |
|
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 PoliciesAPC 2018 FORM 10-K | 95
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies |
General Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketingsale of oil, condensate, natural gas, and natural gas liquids (NGLs),NGLs and in the marketing of anticipated production of liquefied natural gas (LNG).is continuing to advance its Mozambique LNG project toward FID. In addition, the Company engages in the gathering, compressing, treating, processing, treating,and transporting of natural gas; gathering, stabilizing, and transporting of oil natural gas, and NGLs.NGLs; and gathering and disposing of produced water. 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 Statementsconsolidated financial statements have been prepared in conformity with generally accepted accounting principles inGAAP. Certain prior-period amounts have been reclassified to conform to the United States (GAAP). current-year presentation.
The Consolidated Financial Statementsconsolidated financial statements include the accounts of Anadarko and entitiessubsidiaries in which itAnadarko holds, a controlling interest.directly or indirectly, more than 50% of the voting rights and VIEs for which Anadarko is the primary beneficiary. The Company has determined that WGP and WES are VIEs. Anadarko is considered the primary beneficiary and consolidates WGP and WES. WGP and WES function with capital structures that are separate from Anadarko, consisting of their own debt instruments and publicly traded common units. 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-controllednoncontrolled entities over whichthat Anadarko has the ability to exercise significant influence over operating and financial policies and VIEs for which Anadarko is not the primary beneficiary 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 investmentsInvestments are carried at original cost. Investments accounted for usingincluded in other assets on 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.Company’s Consolidated Balance Sheets.
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;AROs; 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.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies (Continued) |
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,When the Company incorporates transaction-specific details that,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 or income approach 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 future net cash flows and discounts the expected cash flows using a commensurate risk-adjusted discount rate. 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, 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 management’s judgment, market participants would take into account in measuring fair value.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
1. Summary of Significant Accounting Policies (Continued)
the Company’s business plans and investment decisions.
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—13—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,AROs, exit or disposal costs, and capital lease assets and liabilities where the present value of lease payments is greater than the fair value of the leased asset.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies (Continued) |
Revenues
2018The Company’s revenue recognition accounting policy effective January 1, 2018, is detailed below.
Exploration and ProductionThe Company’s oil is sold primarily to marketers, gatherers, and condensaterefiners. 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. Payment is generally received from the customer in the month following delivery.
Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. For natural gas and NGLs sold on our behalf by a processor, revenue is typically measured based on the price the processor receives for the sale, less certain costs withheld by the processor.
Revenues are recognized for the sale of Anadarko’s net share of production volume. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.
The Company enters into buy/sell arrangements related to the transportation of a portion of its oil production. These buy/sell transactions are recorded net in oil and gas transportation expense in the Company’s Consolidated Statements of Income.
WES Midstream and Other Midstream Anadarko provides gathering, compressing, treating, processing, stabilizing, transporting, and disposal services pursuant to a variety of contracts. Under these arrangements, the Company receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income. Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally have initial terms ranging from 5 to 10 years.
Revenue is recognized for fee-based gathering and processing services in the month of service based on the volume delivered by the customer. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. The Company may charge additional service fees to customers for a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold) due to the significant upfront capital investment. These fees are recognized as revenue over the expected period of customer benefit, generally the life of the related properties. Deficiency fees, which are charged to the customer if they do not meet minimum delivery requirements, are recognized over the performance period based on an estimate of the deficiency fees that will be billed upon completion of the performance period.
The Company’s midstream business also purchases natural-gas volume from producers at the wellhead or production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. These fees are treated as a reduction of the purchase cost when the fees relate to services performed after control of the product has transferred to Anadarko. If the fees relate to services performed before control of the product has transferred to Anadarko, the fees are treated as Gathering, processing and marketing sales revenues. Revenue is recognized, along with cost of product expense related to the sale, when the purchased product is sold to a third party.
Revenue from percentage of proceeds gathering and processing contracts is recognized net of the cost of product for purchases from service customers when the Company is acting as their agent in the product sale, and any fees charged on these percentage of proceeds contracts are recognized in service revenues.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies (Continued) |
2017 This section reflects the Company’s revenue recognition policies through December 31, 2017, prior to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The Company’s oil is 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 volumesvolume 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 and Restricted Cash Equivalents The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents or restricted cash equivalents.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER The cash equivalents and restricted cash equivalents balance at December 31, 2015, 2014, AND 2013
1. Summary of Significant Accounting Policies (Continued)2018, includes commercial paper and investments in government money market funds in which the carrying value approximates fair value.
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.net realizable value.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies (Continued) |
Properties and Equipment Properties and equipment are stated at cost less accumulated depreciation, depletion, and amortization (DD&A).DD&A. Costs of improvements that appreciably improveextend the efficiency or productive capacitylives 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. Exploratory drilling costs are initially capitalized pending the determination of proved reserves. If anproved reserves are found, drilling costs remain capitalized and are classified as proved properties. For exploratory well provides evidencewells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify potential completion as a producing well drilling costs associated withand sufficient progress is being made in assessing the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantityreserves and the economic and operating viability 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.project. 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.
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—13—Debt and Interest Expense.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies (Continued) |
Asset Retirement Obligations Asset retirement obligations (AROs)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 obligationARO 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—15—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—6—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)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 4740 years for gathering facilities.
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: oilExploration and gas explorationProduction; WES Gathering and production; Western Gas Partners, LP (WES) gatheringProcessing; WES Transportation; and processing; WES transportation; and other gathering and processing.Other Midstream. 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—8—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 with the associated long-lived asset group whenever impairment indicators are present. See Note 7—8—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,other current liabilities, 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—11—Derivative Instruments.
Accounts PayableAPC Accounts payable included liabilities of2018 FORM 10-K $365 million| at101 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.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies (Continued) |
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—18—Contingencies.
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—18—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—24—Noncontrolling Interests.
Income Taxes The Company files various U.S. federal, state, and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. 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—14—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)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 estimatedactual 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—23—Share-Based Compensation.
96102 | APC 2018 FORM 10-K
|
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| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
|
|
| 1. Summary of Significant Accounting Policies (Continued) |
Recently IssuedAdopted Accounting Standards
The FASB issued ASU 2016-01, 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit CostFinancial Instruments—Overall: Recognition and Measurement of Financial Assets and Financial Liabilities (Subtopic 825-10). This ASUamends 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 effectiverequires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item outside operating items. Additionally, only the service cost component of net benefit cost will be eligible for annual periods beginning in 2018 with early adoption of certain provisions permitted.capitalization. The Company is evaluating the impact of the adoption ofadopted this ASU on its consolidated financial statements.January 1, 2018, with retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective presentation for the capitalization of the service cost component of net benefit cost in assets. Upon adoption, non-service cost components of net periodic benefit costs of $107 million for the year ended December 31, 2017, and $225 million for the year ended December 31, 2016, were reclassified to other (income) expense, net, from G&A; oil and gas operating; gathering, processing, and marketing; and exploration expense.
The FASB issued ASU 2015-03, Interest—Imputation2016-18, Statement of Interest (Subtopic 835-30)—Simplifying the Presentation of Debt Issuance CostsCash Flows (Topic 230): Restricted Cash This ASU requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and ASU 2015-15, Interest—Imputationrestricted cash equivalents on the statement of Interest (Subtopic 835-30)—Presentationcash flows and Subsequent Measurementto provide a reconciliation of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require capitalized debt issuance costs, except for thosethe totals in that statement to the related to revolving credit facilities, to be presentedcaptions in the balance sheet as a direct deduction fromwhen the carrying amount ofcash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the related debt liability, rather than as an asset.balance sheet. The Company adopted these ASUsthis ASU using a retrospective approach 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 will2018. Adoption did not have a material impact on the Company’s consolidated financial statements; however, the VIE disclosure requirements will begin to apply in 2016 statements. See Consolidated Statements of Cash Flows and Note 26—Supplemental Cash Flow Informationfor the Company’s interest in WGP and WES.additional information.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which This ASU supersedes the revenue recognition requirements in Topic 605,and industry-specific guidance under Revenue Recognition, and industry-specific guidance in Subtopic 932-605, (Extractive Activities-Oil and Gas-Revenue RecognitionTopic 605) and. Topic 606 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 adopted Topic 606 on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior-period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included a reduction to total equity of $47 million. See Note 2—Revenue from Contracts with Customers for additional information.
ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income This ASU provides entities the option to reclassify stranded tax effects resulting from the Tax Reform Legislation from accumulated other comprehensive income (AOCI) to retained earnings. In accordance with its accounting policy, the Company releases stranded income tax effects from AOCI in the period the underlying portfolio is requiredliquidated. This ASU allows for the reclassification of stranded tax effects as a result of the change in tax rates from the Tax Reform Legislation to adoptbe recorded upon adoption of the newASU, rather than at the actual portfolio liquidation date. The Company adopted this ASU on January 1, 2018, electing to reclassify $73 million from AOCI to retained earnings, including a $2 million federal benefit of state tax impact related to the Tax Reform Legislation.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies (Continued) |
Accounting Standards Adopted in 2019
ASU 2016-02, Leases (Topic 842) This ASU requires lessees to recognize a lease liability and a right-of-use (ROU) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. This standard is effective for periods beginning after December 15, 2018, and in the first quarter of 20182019, the Company fully adopted this standard using onethe modified retrospective method applied to all leases that existed on January 1, 2019. Anadarko made certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases. Upon adoption, the Company recognized approximately $600 million of two retrospective application methods, with earlyROU assets and lease liabilities on its Consolidated Balance Sheet related to leases existing on January 1, 2019. The adoption permitted in 2017. The Company is continuing to evaluate the provisions of this ASU anddid not have a material impact on the Company’s Consolidated Statement of Income or Consolidated Statement of Cash Flows. Anadarko has not determinedidentified any material leases in which Anadarko is a lessor. The Company has implemented the necessary changes to its business processes, systems, and controls to support accounting and disclosure requirements under this ASU.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 2. Revenue from Contracts with Customers |
Change in Accounting PolicyAs stated above, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. See Note 1—Summary of Significant Accounting Policies for additional information.
Impacts on Financial Statements
Exploration and Production There were no significant changes to the timing or valuation of revenue recognized for sales of production by the Exploration and Production reporting segment.
WES Midstream and Other MidstreamGathering and processing revenues decreased for contracts where the Company is acting as an agent for its processing customer in the sale of processed volume and increased for contracts with noncash consideration, with an offset to gathering and processing expense upon product sale. The magnitude of these presentation changes in subsequent periods is dependent on future customer volume subject to the impacted contracts and commodity prices for this volume. These presentation changes do not impact this standard may havenet earnings.
The following tables summarize the impacts of adopting Topic 606 on itsthe Company’s consolidated financial statements and related disclosures or decided upon the method of adoption.statements:
|
| | | | | | | | | | | |
| CONSOLIDATED BALANCE SHEET | Impact of Change in Accounting Policy |
| millions | As Reported |
| Without Adoption of Topic 606 | | Effect of Change Increase/(Decrease) | |
| December 31, 2018 | | | | | |
| Assets | | | | | |
| Other current assets | $ | 474 |
| | $ | 472 |
| | $ | 2 |
|
| Net properties and equipment | 28,615 |
| | 28,548 |
| | 67 |
|
| Other assets | 2,336 |
| | 2,326 |
| | 10 |
|
| Liabilities | | | | | |
| Other current liabilities | 1,295 |
| | 1,290 |
| | 5 |
|
| Deferred income taxes | 2,437 |
| | 2,441 |
| | (4 | ) |
| Other | 4,021 |
| | 3,914 |
| | 107 |
|
| Equity | | | | | |
| Total equity | 10,943 |
| | 10,972 |
| | (29 | ) |
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 2. Revenue from Contracts with Customers (Continued) |
|
| | | | | | | | | | | |
| CONSOLIDATED STATEMENT OF INCOME | Impact of Change in Accounting Policy |
| millions | As Reported |
| Without Adoption of Topic 606 | | Effect of Change Increase/(Decrease) | |
| Year Ended December 31, 2018 | | | | | |
| Revenues | | | | | |
| Gathering, processing, and marketing sales | $ | 1,588 |
| | $ | 2,592 |
| | $ | (1,004 | ) |
| Gains (losses) on divestitures and other, net | 312 |
| | 316 |
| | (4 | ) |
| Expenses | | | | | |
| Gathering, processing, and marketing | 1,047 |
| | 2,075 |
| | (1,028 | ) |
| Income tax expense (benefit) | 733 |
| | 731 |
| | 2 |
|
| Net income (loss) attributable to noncontrolling interests | 137 |
| | 127 |
| | 10 |
|
| Net Income (Loss) Attributable to Common Stockholders | $ | 615 |
| | $ | 607 |
| | $ | 8 |
|
Disaggregation of Revenue from Contracts with CustomersThe following table disaggregates revenue by significant product type and segment:
|
| | | | | | | | | | | | | | | | | | | | |
| millions | Exploration
& Production | | WES Midstream | | Other Midstream | | Other and
Intersegment
Eliminations | | | Total |
|
| Year Ended December 31, 2018 | | | | | | | | | | |
| Oil sales | | $ | 9,206 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 9,206 |
|
| Natural-gas sales | | 1,005 |
| | — |
| | — |
| | — |
| | 1,005 |
|
| Natural-gas liquids sales | | 1,271 |
| | — |
| | — |
| | — |
| | 1,271 |
|
Gathering, processing, and marketing sales(1) | | — |
| | 1,997 |
| | 416 |
| | 21 |
| | 2,434 |
|
| Other, net | | 30 |
| | — |
| | 1 |
| | 97 |
| | 128 |
|
| Total Revenue from Customers | | $ | 11,512 |
| | $ | 1,997 |
| | $ | 417 |
| | $ | 118 |
| | $ | 14,044 |
|
Gathering, processing, and marketing sales(2) | | — |
| | (8 | ) | | 8 |
| | (846 | ) | | (846 | ) |
| Gains (losses) on divestitures, net | | 20 |
| | 1 |
| | 10 |
| | (11 | ) | | 20 |
|
| Other, net | | (34 | ) | | 173 |
| | 40 |
| | (15 | ) | | 164 |
|
| Total Revenue from Other than Customers | | $ | (14 | ) | | $ | 166 |
| | $ | 58 |
| | $ | (872 | ) | | $ | (662 | ) |
| Total Revenue and Other | | $ | 11,498 |
| | $ | 2,163 |
| | $ | 475 |
| | $ | (754 | ) | | $ | 13,382 |
|
| |
(1) | The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $957 million and intersegment eliminations of $(876) million for the year ended December 31, 2018. |
| |
(2) | The amount in Other and Intersegment Eliminations primarily represents purchases of third-party natural gas and NGLs. Although these purchases are reported net in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income, they are shown separately on this table as the purchases are not considered revenue from customers. |
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 2. Revenue from Contracts with Customers (Continued) |
Contract Liabilities Contract liabilities primarily relate to midstream fees and capital reimbursements that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of benefit, fixed and variable fees that are received from customers but revenue recognition is deferred under midstream cost of service contracts, and hard-minerals bonus payments received from customers that must be recognized as revenue over the expected period of benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers:
|
| | | |
| millions | |
| Balance at December 31, 2017 | $ | 37 |
|
| Increase due to cumulative effect of adopting Topic 606 | 98 |
|
| Increase due to cash received, excluding revenues recognized in the period | 66 |
|
| Increase due to assets received from customer | 13 |
|
| Decrease due to revenue recognized | (42 | ) |
| Decrease due to change in estimated consideration | (22 | ) |
| Balance at December 31, 2018 | $ | 150 |
|
| | |
| Contract liabilities at December 31, 2018 | |
| Other current liabilities | $ | 31 |
|
| Other long-term liabilities - other | 119 |
|
| Total contract liabilities from contracts with customers | $ | 150 |
|
Transaction Price Allocated to Remaining Performance Obligations Revenue expected to be recognized from certain performance obligations that are unsatisfied as of December 31, 2018, is reflected in the table below. The Company applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations. Therefore, the following table represents only a small portion of Anadarko’s expected future consolidated revenues as future revenue from the sale of most products and services is dependent on future production or variable customer volume and variable commodity prices for this volume.
|
| | | | | | | | | | | | | | | | | | | | |
| millions | Exploration
& Production | | WES Midstream | | Other Midstream | | Other and
Intersegment
Eliminations | | Total | |
| 2019 | | $ | 104 |
| | $ | 470 |
| | $ | 204 |
| | $ | (432 | ) | | $ | 346 |
|
| 2020 | | 103 |
| | 554 |
| | 293 |
| | (614 | ) | | 336 |
|
| 2021 | | 103 |
| | 534 |
| | 361 |
| | (681 | ) | | 317 |
|
| 2022 | | 7 |
| | 530 |
| | 417 |
| | (740 | ) | | 214 |
|
| 2023 | | 7 |
| | 489 |
| | 424 |
| | (750 | ) | | 170 |
|
| Thereafter | | 58 |
| | 1,802 |
| | 2,763 |
| | (4,077 | ) | | 546 |
|
| Total | | $ | 382 |
| | $ | 4,379 |
| | $ | 4,462 |
| | $ | (7,294 | ) | | $ | 1,929 |
|
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
The following summarizes the major classes of commodity 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 |
|
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
3. Acquisitions, Divestitures, and Assets Held for Sale |
| | | | | | | |
| millions | 2018 |
| | 2017 |
|
| Oil | $ | 139 |
| | $ | 165 |
|
| Natural gas | 18 |
| | 29 |
|
| NGLs | 78 |
| | 122 |
|
| Total commodity inventories | $ | 235 |
| | $ | 316 |
|
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.
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) |
|
| 4. Divestitures and Assets Held for Sale |
Divestitures and Assets Held for SaleThe following summarizes the proceeds received and gains (losses) recognized on divestitures and assets held for sale 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 | ) |
|
| | | | | | | | | | | |
| millions | 2018 |
| | 2017 |
| | 2016 |
|
| Proceeds received, net of closing adjustments | $ | 417 |
| | $ | 4,008 |
| | $ | 2,356 |
|
Gains (losses) on divestitures, net (1) (2) | 20 |
| | 674 |
| | (757 | ) |
| |
(1) | Includes goodwill allocated to divestitures of $209 million in 2017 and $397 million in 2016. |
| |
(2) | Includes gain of $126 million related to the 2017 property exchange discussed below. |
20152018 During the year ended December 31, 2018, the Company divested of the following U.S. onshore and Gulf of Mexico assets:
| |
| – | Alaska nonoperated assets, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $370 million and net losses of $33 million in 2018 and $154 million in the fourth quarter of 2017 |
| |
| – | Ram Powell nonoperated assets in the Gulf of Mexico, included in the Exploration and Production reporting segment, resulting in a net gain of $67 million |
The
2017 During the year ended December 31, 2017, the Company sold certain coalbed methane properties and related midstreamdivested of the following U.S. onshore assets:
| |
| – | Eagleford assets in South Texas, included in the Exploration and Production reporting segment, for net proceeds of $2.1 billion and a net gain of $729 million |
| |
| – | Eaglebine assets in Southeast Texas, included in the Exploration and Production reporting segment, for net proceeds of $533 million and a net gain of $282 million |
| |
| – | Utah CBM assets, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of $69 million and a net loss of $52 million |
| |
| – | Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $951 million and net losses of $55 million in 2017 and $129 million in 2016 |
| |
| – | Moxa assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of $313 million and a net loss of $204 million |
Certain nonoperated assets located in the Rocky Mountains Region (Rockies) for net proceeds of $154 million, after closing adjustments, and recognized a loss of $538 million. These assets wereAlaska included in the oilExploration 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 productionProduction reporting segment as follows:
The Company sold a 10% working interest in Offshore Area 1 in Mozambiquesatisfied criteria to be considered held 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.
Duringsale during the fourth quarter of 2014, Anadarko considered certain EOR2017, at which time the Company remeasured these assets in the Rockies to be held for sale and recognized losses of $456 million. These assets were remeasured to their current fair value using a market approach and Level 2 fair-value measurement. Volatility inmeasurement and recognized a loss of $154 million. At December 31, 2017, the then-current commodity-price environment had reduced the probability that theCompany’s Consolidated Balance Sheet included long‑term assets would be sold within one yearof $573 million and thelong-term liabilities of $27 million associated with assets were therefore no longer considered held for sale at December 31, 2014.sale.
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.108 | APC 2018 FORM 10-K
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. |
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
3. Acquisitions, |
|
| 4. Divestitures and Assets Held for Sale (Continued) |
Property Exchange2016 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 forDuring the year ended December 31, 2013.2016, the Company divested of the following U.S. onshore assets:
| |
| – | Hugoton assets in Kansas, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of $159 million and a loss of $4 million |
| |
| – | Ozona and Steward assets in West Texas, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $221 million and a loss of $52 million |
| |
| – | Wamsutter assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of $588 million and a loss of $58 million |
| |
| – | Elm Grove assets in East Texas, included in the Exploration and Production reporting segment, for net proceeds of $89 million and a loss of $64 million |
| |
| – | East Chalk and Carthage assets in East Texas/Louisiana, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $1.0 billion and a net loss of $439 million |
Certain Marcellus U.S. onshore assets located in Pennsylvania included in the Exploration and Production and Other Midstream reporting segments satisfied criteria to be considered held for sale during the fourth quarter of 2016, at which time the Company remeasured these assets to their current fair value using a market approach and Level 2 fair-value measurement and recognized a loss of $129 million.
4. PropertiesProperty Exchange On March 17, 2017, WES acquired a third party’s 50% nonoperated interest in the DBJV System, now part of the West Texas Complex, in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and Equipment$155 million in cash. WES recognized a gain of $126 million as a result of this transaction. After the acquisition, the DBJV System is 100% owned by WES and consolidated by Anadarko.
|
|
| 5. Properties and Equipment |
The following summarizes properties and equipment by segment at December 31:
| | | millions | 2015 | | 2014 | 2018 |
| | 2017 |
|
Oil and gas exploration and production (1) | $ | 59,389 |
| | $ | 63,674 |
| |
| Midstream | 8,458 |
| | 8,647 |
| |
Exploration and Production (1) | | $ | 51,941 |
| | $ | 49,388 |
|
| WES Midstream | | 9,250 |
| | 7,865 |
|
| Other Midstream | | 2,908 |
| | 2,012 |
|
| Other | 2,836 |
| | 2,786 |
| 2,421 |
| | 2,293 |
|
| Gross properties and equipment | $ | 70,683 |
| | $ | 75,107 |
| $ | 66,520 |
| | $ | 61,558 |
|
| Less accumulated depreciation, depletion, and amortization | 36,932 |
| | 33,518 |
| |
| Less accumulated DD&A | | 37,905 |
| | 34,107 |
|
| Net properties and equipment | $ | 33,751 |
| | $ | 41,589 |
| $ | 28,615 |
| | $ | 27,451 |
|
| |
(1) | Includes costs associated with unproved properties of $3.5$1.7 billion at December 31, 2015,2018, and $5.1$2.4 billion at December 31, 2014. 2017. |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
5. Impairments
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
Impairments of proved propertiesLong-Lived Assets Impairments of long-lived assets are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of proved propertieslong-lived assets 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| millions | Impairment | | Fair Value (1) | | | Impairment | | Fair Value (1) | | | Impairment | | Fair Value (1) | |
| Exploration and Production | | | | | | | | | | | | | | |
| U.S. onshore properties | | $ | 347 |
| | $ | 100 |
| | | $ | 2 |
| | $ | 3 |
| | | $ | 28 |
| | $ | 617 |
|
| Gulf of Mexico properties | | 27 |
| | — |
| | | 227 |
| | 216 |
| | | 27 |
| | 61 |
|
| Cost-method investment | | — |
| | — |
| | | — |
| | — |
| | | 59 |
| | — |
|
| WES Midstream | | 228 |
| | 30 |
| | | 176 |
| | 58 |
| | | 16 |
| | 3 |
|
| Other Midstream | | 53 |
| | 72 |
| | | 2 |
| | — |
| | | 57 |
| | 29 |
|
| Other | | 145 |
| | 15 |
| | | 1 |
| | — |
| | | 40 |
| | — |
|
| Total impairments | | $ | 800 |
| | $ | 217 |
| | | $ | 408 |
| | $ | 277 |
| | | $ | 227 |
| | $ | 710 |
|
| |
(1) | Measured as of the impairment date using the income approach and Level 3 inputs. |
| |
(2)
| Represents the after-tax The primary assumptions used to estimate undiscounted future net investment.cash flows include anticipated future production, commodity prices, and capital and operating costs. |
2015 2018 ImpairmentsIn 2015, impairments were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties due to the steep decline in NGL commodity prices in the fourth quarter of 2018 and a gathering system in the DJ basin that was permanently taken out of service in the second quarter of 2018. Impairments also related to hard-minerals properties as a result of the Company’s primary consumer of coal stating its intent to retire its existing coal-fired power generation plant earlier than expected, coupled with the outlook for limited new markets for the Company’s coal in the Rockies other U.S. onshore oil and gas propertiesregion.
2017 Impairments were primarily in the Southern and Appalachia Region, other midstream properties primarily in the Rockies, andrelated to oil and gas properties in the Gulf of Mexico all of which were impaired due to lower forecasted commodity prices.prices and a U.S. onshore midstream property due to a reduced throughput fee as a result of a producer’s bankruptcy.
2014 Impairments2016 In 2014,Impairments were primarily related to the uncertain recovery of the Company’s Venezuelan cost-method investment, negative developments related to commercial negotiations of a certain midstream asset, impairment of an office building, changes in development plans for 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 flowsassets, 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.flows related to an oil and gas property in the Gulf of Mexico.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 6. Impairments (Continued) |
Impairments of Unproved PropertiesImpairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. In 2015,
2018 The Company recognized $159 million of impairments of unproved Gulf of Mexico properties primarily related to GOM blocks where the Company determined it would no longer pursue exploration activities.
2017 The Company recognized $610 million of impairments of unproved Gulf of Mexico properties primarily due to an impairment of $463 million to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to Gulf of Mexico exploration projects from the acquisition of Kerr-McGee Corporation in 2006. The Company also recognized $88 million of impairments of unproved international properties. See Note 7—Suspended Exploratory Well Costs.
2016 The Company recognized a $935$72 million impairment of unproved Greater Natural Buttes properties and a $66 million impairment of an unprovedin the Gulf of Mexico property as a result of lower commodity prices. Also in 2015, the Company recognized a $109and $92 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.
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 gasinternational properties primarily as a result of lower forecasted commodity pricesin Brazil and changesTunisia due to the Company’s drilling plans. At December 31, 2015, the Company’s estimate of undiscountedintentions to not pursue 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. exploration activities.
It is also reasonably possible that prolonged low or furthersignificant declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in other additional impairments.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 7. 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.years:
| | | millions | 2015 | | 2014 | | 2013 | 2018 |
| | 2017 |
| | 2016 |
|
| Balance at January 1 | $ | 1,522 |
| | $ | 2,232 |
| | $ | 2,062 |
| $ | 525 |
| | $ | 1,230 |
| | $ | 1,124 |
|
Additions pending the determination of proved reserves | 461 |
| | 421 |
| | 848 |
| 90 |
| | 349 |
| | 490 |
|
Divestitures and other (1) | (33 | ) | | (913 | ) | | (48 | ) | (38 | ) | | (36 | ) | | (11 | ) |
| Reclassifications to proved properties | (104 | ) | | (100 | ) | | (507 | ) | (132 | ) | | (41 | ) | | (50 | ) |
Charges to exploration expense (2) | (722 | ) | | (118 | ) | | (123 | ) | (1 | ) | | (977 | ) | | (323 | ) |
| Balance at December 31 | $ | 1,124 |
| | $ | 1,522 |
| | $ | 2,232 |
| $ | 444 |
| | $ | 525 |
| | $ | 1,230 |
|
| |
(1) | Includes $(744)Excludes amounts capitalized and subsequently charged to expense within the same year. |
2018 During the year ended December 31, 2018, the Company expensed $87 million of exploratory well costs, including $1 million of costs that were suspended as of December 31, 2017.
2017 During the year ended December 31, 2017, exploratory well costs charged to exploration expense primarily related to the following:
Gulf of Mexico
| |
| – | ShenandoahThe Company expensed $437 million during 2014 related toof exploratory well costs, including $326 million of costs that were suspended as of December 31, 2016. The Shenandoah-6 appraisal well and subsequent sidetrack, which completed appraisal activities in April 2017 and did not encounter oil in the Company’s saleeastern portion of a 10% workingthe field. Given the results of this well and the commodity-price environment at the time, the Company suspended further appraisal activities. In 2018, the Company relinquished its ownership interest in Offshore Area 1 in Mozambique.Shenandoah. |
| |
| – | (2)Phobos
| Includes $(565) The Company expensed $215 million during 2015of exploratory well costs, including $99 million of costs that were suspended as of December 31, 2016, in the third quarter of 2017 related to Brazil. Givenwells at the Phobos project. These wells found insufficient quantities of oil pay to justify development in the current oil-price environmentprice environment. |
| |
| – | Warrior The Company expensed $108 million of exploratory well costs in the third quarter of 2017 related to the northern appraisal well and other considerations,sidetrack at the Warrior project. These wells found insufficient quantities of oil pay to justify development of the northern portion of the field in the current price environment. Evaluation of tie-back opportunities in the southern portion of the field is ongoing. |
Colombia
| |
| – | The Company expensed $243 million of exploratory well costs, including $109 million of costs that were suspended as of December 31, 2016, related to wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater gas development. All remaining leases are contractually in good standing. |
Côte d’Ivoire
| |
| – | The Company expensed $329 million of exploratory well costs, including $237 million of costs that were suspended as of December 31, 2016, in Côte d’Ivoire. During 2017, the Company doeshad unsuccessful drilling activities in the south channel of the Paon prospect and in Block CI-527 and after further evaluation of the well results Anadarko withdrew from all exploration blocks in Côte d’Ivoire. The Company expects to complete the withdrawal from its remaining appraisal block in 2019. |
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 7. Suspended Exploratory Well Costs (Continued) |
2016 During the year ended December 31, 2016, suspended exploratory well costs charged to exploration expense primarily related to the following:
Gulf of Mexico
| |
| – | The Company expensed $231 million of suspended exploratory well costs in the Gulf of Mexico primarily related to the Yeti project, as the Company did not expect to have substantive exploration and development activities in Brazilon this prospect in the foreseeable future.future, and a Shenandoah well that was expensed, as it was no longer reasonably possible that the wellbore could be used in the development of the project. |
Mozambique
| |
| – | The Company expensed $92 million of suspended exploratory well costs in Mozambique. The Tubarão-Tigre discovery wells were expensed based on the outlook for development viability, the commodity market conditions, and the complexity introduced by the depth and characteristics of the reservoir. The Orca-4 well was expensed after additional reservoir analysis and the determination that the well was not associated with the first three Orca wells. |
The following provides an aging of suspended well balances at December 31:
| | | millions | 2015 | | 2014 | | 2013 | 2018 |
| | 2017 |
| | 2016 |
|
| Exploratory well costs capitalized for a period of one year or less | $ | 452 |
| | $ | 393 |
| | $ | 836 |
| $ | 152 |
| | $ | 201 |
| | $ | 460 |
|
| Exploratory well costs capitalized for a period greater than one year | 672 |
| | 1,129 |
| | 1,396 |
| 292 |
| | 324 |
| | 770 |
|
| Balance at December 31 | $ | 1,124 |
| | $ | 1,522 |
| | $ | 2,232 |
| $ | 444 |
| | $ | 525 |
| | $ | 1,230 |
|
102APC 2018 FORM 10-K | 113
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
6. |
|
| 7. 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, 2015:2018:
| | | millions except projects | Number of Projects | | Total | | 2014 | | 2013 | | 2012 and prior | Number of Projects | | Total |
| | 2017 |
| | 2016 |
| | 2015 and
prior |
|
| United States—Onshore | 18 | | $ | 55 |
| | $ | 34 |
| | $ | 11 |
| | $ | 10 |
| |
| United States—Offshore | 4 | | 314 |
| | 77 |
| | 80 |
| | 157 |
| |
| U.S. onshore | | 1 | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| U.S. offshore | | 1 | | 73 |
| | (1 | ) | | 74 |
| | — |
|
| International | 7 | | 303 |
| | 119 |
| | 3 |
| | 181 |
| 3 | | 217 |
| | 11 |
| | 14 |
| | 192 |
|
| | 29 | | $ | 672 |
| | $ | 230 |
| | $ | 94 |
| | $ | 348 |
| 5 | | $ | 292 |
| | $ | 10 |
| | $ | 88 |
| | $ | 194 |
|
Projects with suspendedFor exploratory wellwells, drilling costs are those identified by management as exhibitingcapitalized, or “suspended,” on the balance sheet when the well has found a sufficient quantitiesquantity of hydrocarbonsreserves to justify potential developmentits completion as a producing well and where managementsufficient progress is actively pursuing efforts to assess whetherbeing made in assessing the reserves can be attributed to these projects.and the economic and operating viability of the project. Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling at December 31, 2015,2018, primarily related to the Gulf of Mexico, Ghana, and Mozambique.
For projects located in the
Gulf of Mexico the majority of exploratory Exploratory well costs capitalized greater than one year are primarily related to the Shenandoah discovery. Well costsWarrior discovery and 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 relatedpotential tieback to the Orca, Tubarão, and Tubarão Tigre discoveries. Well costs have been suspended pending further appraisal activities,existing infrastructure, including analysis of well results and seismic reprocessing. During 2015, drillinggeologic and evaluation operations at the Tubarão Tigre-2 appraisalgeophysical studies, and project sanctioning.
Ghana Exploratory well were completed. Anadarko is continuing to appraise the Orca, Tubarão, and Tubarão Tigre discoveries in accordance with the appraisal programs providedcosts are related to the Mahogany East and Teak prospects, which are included in the Greater Jubilee Full Field Development Plan approved by the Ghanaian government in October 2017. Well costs remain suspended pending further technical analysis and future drilling results.
MozambiqueExploratory well costs are related to the initial two-train Golfinho/Atum project. In 2018, the Company obtained government approval of Mozambiquethe Development Plan, advanced major infrastructure projects, advanced onshore and offshore construction and installation contracts, executed long-term LNG sales and purchase agreements (SPAs), and launched project financing. During 2018 and subsequent to year end, additional SPAs were executed, increasing the contracted volume to more than 7.5 MTPA. Execution of SPAs representing 2.0 MTPA of additional contracted volume is anticipated prior to FID. The Company is working to finalize project finance arrangements with lenders and secure all partner and government-related approvals required to proceed with making a final investment decision in the first quarterhalf of 2015.2019.
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.
103114 | APC 2018 FORM 10-K
ANADARKO PETROLEUM CORPORATION |
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 20137. Goodwill and Other Intangible Assets |
|
| 8. Goodwill and Other Intangible Assets |
Goodwill At December 31, 2015,2018, the Company had $5.4$4.8 billion of goodwill allocated to the following reporting units: $4.9segments: $4.3 billion to oilExploration and gas exploration and production, $383Production, $416 million to WES gatheringMidstream, and processing, $5$30 million to WES transportation, and $62 million to other gathering and processing.Other Midstream. The Company’s 20152018 annual qualitative impairment assessment of goodwill indicated no impairment. An additional assessment wasQualitative factors were also performedassessed in December 2015the fourth quarter of 2018 to consider the impact of commodity-pricereview any changes sincein circumstances subsequent to the annual test.test, including changes in commodity prices. 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:follows at December 31:
|
| | | | | | | | | | | | | | | |
| 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 |
|
|
| | | | | | | |
| millions | 2018 |
| | 2017 |
|
| Gross carrying amount | $ | 980 |
| | $ | 1,013 |
|
| Accumulated amortization | (139 | ) | | (140 | ) |
| Net carrying amount | $ | 841 |
| | $ | 873 |
|
| Amortization expense | $ | 32 |
| | $ | 31 |
|
Customer contract intangibleIntangible assets are primarily related to customer contracts associated with WES’s DBM2014 acquisition in 2014.of Delaware basin processing infrastructure. 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$32 million for each of the next five years.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
8. Equity-Method Investments
|
|
| 9. 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) basedLIBOR-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.billion, each with a 35-year term. 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, 2015.2018. Anadarko’s noncontrolling interest may be redeemed beginning in 2022 by Anadarko or the owner of the controlling interest. Anadarko’s interest is mandatorily redeemable in 2037. 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 investmentsinvestment for each entity and the obligationsrelated obligation are presented net on the Company’s Consolidated Balance Sheets in otherSheets. Other long-term liabilities—other for all periods presented.included $41 million at December 31, 2018, and $46 million at December 31, 2017, and other assets included $4 million at December 31, 2018 and $4 million at December 31, 2017, related to these investments.
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%3.79% at December 31, 2015,2018, and 1.24%2.59% at December 31, 2014.2017. The note payable agreement contains a quarterly 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, 2015.2018. Other (income) expense, net includes interest expense on the notes payable of $37$91 million in 2015, $362018, $64 million in 2014,2017, and $37$49 million in 2013,2016, and equity (earnings) losses from Anadarko’s investments in the investee entities of $15of$(87) million in 2015, $(45)2018, $(56) million in 2014,2017, and $(42)$(33) million in 2016.
APC 20132018 FORM 10-K .| 115
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
9. Derivative InstrumentsAccounts Payable Accounts payable, trade included liabilities of $180 million at December 31, 2018, and $219 million at December 31, 2017, 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 classified as cash flows from financing activities.
Other Current Liabilities The following summarizes the Company’s other current liabilities at December 31:
|
| | | | | | | |
| millions | 2018 |
| | 2017 |
|
| Accrued income taxes | $ | 167 |
| | $ | 71 |
|
| Interest payable | 267 |
| | 246 |
|
| Production, property, and other taxes payable | 309 |
| | 216 |
|
| Accrued employee benefits | 319 |
| | 210 |
|
| Derivatives | 89 |
| | 384 |
|
| Other | 144 |
| | 183 |
|
| Total other current liabilities | $ | 1,295 |
| | $ | 1,310 |
|
|
|
| 11. 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.oil and Henry Hub, Louisiana for natural gas. 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).facilities.
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) whenis subject to changes in interest rates increase (decrease).rates.
The Company does not apply hedge accounting to any of its currently outstanding 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—22—Accumulated Other Comprehensive Income (Loss).
105116 | APC 2018 FORM 10-K
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
9. |
|
| 11. 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 IntermediateNYMEX WTI and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The Company had no natural-gas prices listed below are NYMEX Henry Hub prices. The NGLs prices listed below are Oil Price Information Services prices (OPIS).production/processing derivatives at December 31, 2018. The following is a summary of the Company’s oil derivative instruments related to oil and natural-gas production/processing derivative activities at December 31, 2015:2018:
|
| | | | |
| | | 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 |
| | | | |
| | 2019 Settlement | |
| Oil | | |
| Three-Way Collars (MBbls/d) | | 87 |
|
| Average price per barrel | | |
| Ceiling sold price (call) | | $ | 72.98 |
|
| Floor purchased price (put) | | $ | 56.72 |
|
| Floor sold price (put) | | $ | 46.72 |
|
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.volume. The purchased put establishes the minimum price that the Company will receive for the contracted volumesvolume 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
9. Derivative Instruments (Continued)
Anadarko Interest-Rate Derivatives (Excluding WES) 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,August 2018, the Company extended the reference-period start dates onamended an interest-rate swapsswap with an aggregatea notional principal amount of $1.0 billion to align the portfolio with anticipated debt refinancing. The Company also amended$200 million, extending 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 requireddate from 2018 to be settled2023 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 inexchange for a cash payment of $222approximately $10 million.
At December 31, 2018, the Company had outstanding interest-rate swaps with a notional amount of $1.6 billion due prior to or in September 2023 that manage interest-rate risk associated with potential future debt issuances. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions or settle or amend certain or all of the currently outstanding interest-rate swaps. The Company had the following outstanding interest-rate swaps at December 31, 2018:
|
| | | | | | | |
| millions except percentages | | Mandatory | Weighted-Average |
|
| Notional Principal Amount | Reference Period | Termination Date | Interest Rate |
|
| $ | 550 |
| | September 2016 - 2046 | September 2020 | 6.418 | % |
| $ | 250 |
| | September 2016 - 2046 | September 2022 | 6.809 | % |
| $ | 100 |
| | September 2017 - 2047 | September 2020 | 6.891 | % |
| $ | 250 |
| | September 2017 - 2047 | September 2021 | 6.570 | % |
| $ | 450 |
| | September 2017 - 2047 | September 2023 | 6.445 | % |
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’sAnadarko’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization, or collateralizationcash payments for amendments related to these extended interest-rate derivatives are classified as cash flows from financing activities. Net cash payments related to settlements and amendments of interest-rate swap agreements were $92 million in 2018 and $112 million in 2017.
The Company had
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 11. Derivative Instruments (Continued) |
WES Interest-Rate Derivatives In December 2018, WES entered into interest-rate swap agreements with an aggregate notional amount of $750 million to manage interest-rate risk associated with anticipated 2019 debt issuances. WES has locked in a fixed interest rate in exchange for a floating interest rate indexed to the followingthree-month LIBOR. Depending on market conditions, liability management actions, or other factors, WES may settle or amend certain or all of the currently outstanding interest-rate swaps. The following interest-rate swaps were outstanding at December 31, 2015:2018:
|
| | | | | | | | | |
| 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% |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
9. Derivative Instruments (Continued) |
| | | | | | | |
| millions except percentages | | Mandatory | Fixed |
|
| Notional Principal Amount | Reference Period | Termination Date | Interest Rate |
|
| $ | 250 |
| | December 2019 - 2024 | December 2019 | 2.730 | % |
| $ | 250 |
| | December 2019 - 2029 | December 2019 | 2.856 | % |
| $ | 250 |
| | December 2019 - 2049 | December 2019 | 2.905 | % |
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 | Gross Derivative Assets | | Gross Derivative Liabilities |
| Balance Sheet Classification | | 2015 | | 2014 | | 2015 | | 2014 | | 2018 |
| | 2017 |
| | 2018 |
| | 2017 |
|
| Commodity derivatives | | | | | | | | | |
Commodity derivatives - Anadarko (1) | | | | | | | | | |
| Other current assets | | $ | 462 |
| | $ | 421 |
| | $ | (177 | ) | | $ | (118 | ) | | $ | 300 |
| | $ | 7 |
| | $ | (126 | ) | | $ | (1 | ) |
| Other assets | | 8 |
| | 1 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
|
| Accrued expenses | | — |
| | 71 |
| | (3 | ) | | (114 | ) | |
| Other current liabilities | | | 1 |
| | 45 |
| | (6 | ) | | (206 | ) |
| Other liabilities | | — |
| | — |
| | — |
| | (6 | ) | | — |
| | — |
| | — |
| | (2 | ) |
| | | 470 |
| | 493 |
| | (180 | ) | | (238 | ) | | 301 |
| | 54 |
| | (132 | ) | | (209 | ) |
| Interest-rate derivatives | | | | | | | | | |
Interest-rate derivatives - Anadarko (1) | | | | |
| | | |
|
| Other current assets | | 2 |
| | — |
| | — |
| | — |
| | 22 |
| | 14 |
| | — |
| | — |
|
| Other assets | | 54 |
| | — |
| | — |
| | — |
| | 34 |
| | 40 |
| | — |
| | — |
|
| Accrued expenses | | — |
| | — |
| | (54 | ) | | — |
| |
| Other current liabilities | | | — |
| | — |
| | (82 | ) | | (236 | ) |
| Other liabilities | | — |
| | — |
| | (1,488 | ) | | (1,217 | ) | | — |
| | — |
| | (1,156 | ) | | (1,183 | ) |
| | | 56 |
| | — |
| | (1,542 | ) | | (1,217 | ) | | 56 |
| | 54 |
| | (1,238 | ) | | (1,419 | ) |
| Interest-rate derivatives - WES | | | | | | | | | |
| Other current liabilities | | | — |
| | — |
| | (8 | ) | | — |
|
| Total derivatives | | $ | 526 |
| | $ | 493 |
| | $ | (1,722 | ) | | $ | (1,455 | ) | | $ | 357 |
| | $ | 108 |
| | $ | (1,378 | ) | | $ | (1,628 | ) |
| |
(1) | Excludes amounts related to WES interest-rate swap agreements. |
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 11. Derivative Instruments (Continued) |
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 | 2018 |
| | 2017 |
| | 2016 |
|
| Commodity derivatives | | | | | | | |
Commodity derivatives - Anadarko (1) | | | | | | |
Gathering, processing, and marketing sales (1) | | $ | (1 | ) | | $ | 10 |
| | $ | 6 |
| $ | 8 |
| | $ | (4 | ) | | $ | 6 |
|
| (Gains) losses on derivatives, net | | (367 | ) | | (589 | ) | | 141 |
| 213 |
| | 3 |
| | 147 |
|
| Interest-rate derivatives | | | | | | | |
Interest-rate derivatives - Anadarko (1) | | | |
| |
|
| (Gains) losses on derivatives, net | | (91 | ) | | 132 |
| | 139 |
|
| Interest-rate derivatives - WES | | | | | | |
| (Gains) losses on derivatives, net | | 268 |
| | 786 |
| | (539 | ) | 8 |
| | — |
| | — |
|
| Total (gains) losses on derivatives, net | | $ | (100 | ) | | $ | 207 |
| | $ | (392 | ) | $ | 138 |
| | $ | 131 |
| | $ | 292 |
|
| |
(1) | Represents the effect of Marketing and Trading Derivative Activities.Excludes amounts related to WES interest-rate swap agreements. |
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 portfolio valuation versus negotiated credit thresholds. These credit thresholds may alsogenerally require full or partial collateralization or immediate settlement of the Company’s obligations ifdepending on 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 isS&P and Moody’s. As of December 31, 2018, the Company’s long-term debt was rated investment grade (BBB) by both S&P and Fitch and below investment grade. Previously, most of the Company’s derivative counterparties maintained secured positionsgrade (Ba1) by Moody’s. Subsequent to year end, Moody’s changed its outlook 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, theits rating from stable to positive. The Company may be required from time to time to post additional collateral of cashwith respect to its derivative instruments if its credit ratings decline below current levels or letters ofif the liability associated with any such derivative instrument increases above the credit based on the negotiated terms of the individual derivative agreements.threshold. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.3$1.1 billion (net of $66 million of collateral) at December 31, 2015,2018, and $97$1.4 billion (net of $170 million (net of collateral) at December 31, 2014. For information on the Company’s revolving credit facilities, see2017.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
9. |
|
| 11. 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 | Level 1 |
| | Level 2 |
| | Level 3 |
| | Netting (1) |
| Collateral | | | Total |
|
| December 31, 2015 | | | | | | | | | | | | |
| December 31, 2018 | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | | | | | | | | |
Anadarko (2) | | | | | | | | | | | | |
| Commodity derivatives | $ | 10 |
| | $ | 460 |
| | $ | — |
| | $ | (178 | ) | | $ | (8 | ) | | $ | 284 |
| $ | 1 |
| | $ | 300 |
| | $ | — |
| | $ | (127 | ) | | $ | — |
| | $ | 174 |
|
| Interest-rate derivatives | — |
| | 56 |
| | — |
| | — |
| | — |
| | 56 |
| — |
| | 56 |
| | — |
| | — |
| | — |
| | 56 |
|
| Total derivative assets | $ | 10 |
| | $ | 516 |
| | $ | — |
| | $ | (178 | ) | | $ | (8 | ) | | $ | 340 |
| $ | 1 |
| | $ | 356 |
| | $ | — |
| | $ | (127 | ) | | $ | — |
| | $ | 230 |
|
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
Anadarko (2) | | | | | | | | | | | | |
| Commodity derivatives | | $ | (2 | ) | | $ | (130 | ) | | $ | — |
| | $ | 127 |
| | $ | 2 |
| | $ | (3 | ) |
| Interest-rate derivatives | | — |
| | (1,238 | ) | | — |
| | — |
| | 66 |
| | (1,172 | ) |
| WES | | | | | | | | | | | | |
| Interest-rate derivatives | | — |
| | (8 | ) | | — |
| | — |
| | — |
| | (8 | ) |
| Total derivative liabilities | | $ | (2 | ) | | $ | (1,376 | ) | | $ | — |
| | $ | 127 |
| | $ | 68 |
| | $ | (1,183 | ) |
| | | | | | | | | | | | | |
| December 31, 2017 | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | |
Anadarko (2) | | | | | | | | | | | | |
| Commodity derivatives | | $ | 1 |
| | $ | 53 |
| | $ | — |
| | $ | (46 | ) | | $ | (1 | ) | | $ | 7 |
|
| Interest-rate derivatives | | — |
| | 54 |
| | — |
| | — |
| | — |
| | 54 |
|
| Total derivative assets | | $ | 1 |
| | $ | 107 |
| | $ | — |
| | $ | (46 | ) | | $ | (1 | ) | | $ | 61 |
|
| Liabilities | | | | | | | | | | | | |
Anadarko (2) | | | | | | | | | | | | |
| Commodity derivatives | $ | (1 | ) | | $ | (179 | ) | | $ | — |
| | $ | 178 |
| | $ | — |
| | $ | (2 | ) | $ | (1 | ) | | $ | (208 | ) | | $ | — |
| | $ | 46 |
| | $ | 3 |
| | $ | (160 | ) |
| Interest-rate derivatives | — |
| | (1,542 | ) | | — |
| | — |
| | 58 |
| | (1,484 | ) | — |
| | (1,419 | ) | | — |
| | — |
| | 170 |
| | (1,249 | ) |
| Total derivative liabilities | $ | (1 | ) | | $ | (1,721 | ) | | $ | — |
| | $ | 178 |
| | $ | 58 |
| | $ | (1,486 | ) | $ | (1 | ) | | $ | (1,627 | ) | | $ | — |
| | $ | 46 |
| | $ | 173 |
| | $ | (1,409 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| 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. |
| |
(2) | Excludes amounts related to WES interest-rate swap agreements. |
110120 | APC 2018 FORM 10-K
ANADARKO PETROLEUM CORPORATION |
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 201310. Tangible Equity Units |
|
| 12. Tangible Equity Units |
In June 2015, the Company issued 9.2 million 7.50% tangible equity units (TEUs)TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU iswas 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 iswas considered a freestanding financial instrument, indexed to WGP common units, and meetsmet 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 atOn June 7, 2018, the holder’s option, each purchase contract has a mandatory settlement date, Anadarko settled 9.2 million outstanding TEUs in exchange for approximately 8.2 million WGP common units based on the determined final settlement rate of 0.8921 WGP common units per outstanding TEU. See settlement of tangible equity units in the Company’s Consolidated Statement of Equity.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
| | 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 shares13. Debt and Interest Expense |
__________________________________________________________________
Debt Activity The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions:
|
| | | | | | | | | | | | | | | | |
| | Carrying Value | |
| millions | WES |
| WGP (1) | | Anadarko (2) | | Anadarko Consolidated | | Description |
| Balance at December 31, 2016 | $ | 3,091 |
| | $ | 28 |
| | $ | 11,959 |
| | $ | 15,078 |
| |
| Borrowings | | | | | | | | |
| | 370 |
| | — |
| | — |
| | 370 |
| WES RCF |
| Repayments | | | | | | | | |
| | — |
| | — |
| | (6 | ) | | (6 | ) | 7.000% Debentures due 2027 |
| | — |
| | — |
| | (3 | ) | | (3 | ) | 6.625% Debentures due 2028 |
| | — |
| | — |
| | (1 | ) | | (1 | ) | 7.950% Debentures due 2029 |
| | — |
| | — |
| | (34 | ) | | (34 | ) | TEUs - senior amortizing notes |
| Other, net | 4 |
| | — |
| | 50 |
| | 54 |
| Amortization of discounts, premiums, and debt issuance costs |
| Balance at December 31, 2017 | $ | 3,465 |
| | $ | 28 |
| | $ | 11,965 |
| | $ | 15,458 |
| |
| Issuances | | | | | | | | |
| | 394 |
| | — |
| | — |
| | 394 |
| WES 4.500% Senior Notes due 2028 |
| | 687 |
| | — |
| | — |
| | 687 |
| WES 5.300% Senior Notes due 2048 |
| | 396 |
| | — |
| | — |
| | 396 |
| WES 4.750% Senior Notes due 2028 |
| | 342 |
| | — |
| | — |
| | 342 |
| WES 5.500% Senior Notes due 2048 |
| Borrowings | | | | | | | | |
| | 540 |
| | — |
| | — |
| | 540 |
| WES RCF |
| Repayments | | | | | | | | |
| | — |
| | — |
| | (114 | ) | | (114 | ) | 7.050% Debentures due 2018 |
| | — |
| | — |
| | (123 | ) | | (123 | ) | 4.850% Senior Notes due 2021 |
| | — |
| | — |
| | (375 | ) | | (375 | ) | 3.450% Senior Notes due 2024 |
| | — |
| | — |
| | (35 | ) | | (35 | ) | Zero Coupon Notes due 2036 |
| | (350 | ) | | — |
| | — |
| | (350 | ) | WES 2.600% Senior Notes due 2018 |
| | (690 | ) | | — |
| | — |
| | (690 | ) | WES RCF |
| | — |
| | — |
| | (17 | ) | | (17 | ) | TEUs - senior amortizing notes |
| Other, net | 3 |
| | — |
| | 53 |
| | 56 |
| Amortization of discounts, premiums, and debt issuance costs |
| Balance at December 31, 2018 | $ | 4,787 |
| | $ | 28 |
| | $ | 11,354 |
| | $ | 16,169 |
| |
| |
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,(2)
| Excludes WES and including, the 23rd scheduled trading day immediately preceding June 7, 2018.WGP. |
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
122 | 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.2018 FORM 10-K
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
11. Debt and Interest Expense |
|
| 13. Debt and Interest Expense (Continued) |
Debt The Company’s outstanding debt, excluding the capital lease obligation, is senior unsecured. See Note 8—9—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:debt, including capital lease obligations, after eliminating the effect of intercompany transactions: | | | | December 31, | December 31, 2018 |
| millions | 2015 | | 2014 | WES |
| WGP (1) | | Anadarko (2) | | Anadarko Consolidated | |
| 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 |
| $ | — |
| | $ | — |
| | $ | 300 |
| | $ | 300 |
|
| 8.700% Senior Notes due 2019 | 600 |
| | 600 |
| — |
| | — |
| | 600 |
| | 600 |
|
| 4.850% Senior Notes due 2021 | | — |
| | — |
| | 677 |
| | 677 |
|
| WES 5.375% Senior Notes due 2021 | 500 |
| | 500 |
| 500 |
| | — |
| | — |
| | 500 |
|
| WES 4.000% Senior Notes due 2022 | 670 |
| | 670 |
| 670 |
| | — |
| | — |
| | 670 |
|
| 3.450% Senior Notes due 2024 | 625 |
| | 625 |
| — |
| | — |
| | 248 |
| | 248 |
|
| 6.950% Senior Notes due 2024 | 650 |
| | 650 |
| — |
| | — |
| | 650 |
| | 650 |
|
| WES 3.950% Senior Notes due 2025 | 500 |
| | — |
| 500 |
| | — |
| | — |
| | 500 |
|
| WES 4.650% Senior Notes due 2026 | | 500 |
| | — |
| | — |
| | 500 |
|
| 5.550% Senior Notes due 2026 | | — |
| | — |
| | 1,100 |
| | 1,100 |
|
| 7.500% Debentures due 2026 | 112 |
| | 112 |
| — |
| | — |
| | 112 |
| | 112 |
|
| 7.000% Debentures due 2027 | 54 |
| | 54 |
| — |
| | — |
| | 48 |
| | 48 |
|
| 7.125% Debentures due 2027 | 150 |
| | 150 |
| — |
| | — |
| | 150 |
| | 150 |
|
| WES 4.500% Notes due 2028 | | 400 |
| | — |
| | — |
| | 400 |
|
| WES 4.750% Notes due 2028 | | 400 |
| | — |
| | — |
| | 400 |
|
| 6.625% Debentures due 2028 | 17 |
| | 17 |
| — |
| | — |
| | 14 |
| | 14 |
|
| 7.150% Debentures due 2028 | 235 |
| | 235 |
| — |
| | — |
| | 235 |
| | 235 |
|
| 7.200% Debentures due 2029 | 135 |
| | 135 |
| — |
| | — |
| | 135 |
| | 135 |
|
| 7.950% Debentures due 2029 | 117 |
| | 117 |
| — |
| | — |
| | 116 |
| | 116 |
|
| 7.500% Senior Notes due 2031 | 900 |
| | 900 |
| — |
| | — |
| | 900 |
| | 900 |
|
| 7.875% Senior Notes due 2031 | 500 |
| | 500 |
| — |
| | — |
| | 500 |
| | 500 |
|
| Zero-Coupon Senior Notes due 2036 | 2,360 |
| | 2,360 |
| |
| Zero Coupon Senior Notes due 2036 | | — |
| | — |
| | 2,270 |
| | 2,270 |
|
| 6.450% Senior Notes due 2036 | 1,750 |
| | 1,750 |
| — |
| | — |
| | 1,750 |
| | 1,750 |
|
| 7.950% Senior Notes due 2039 | 325 |
| | 325 |
| — |
| | — |
| | 325 |
| | 325 |
|
| 6.200% Senior Notes due 2040 | 750 |
| | 750 |
| — |
| | — |
| | 750 |
| | 750 |
|
| 4.500% Senior Notes due 2044 | 625 |
| | 625 |
| — |
| | — |
| | 625 |
| | 625 |
|
| WES 5.450% Senior Notes due 2044 | 400 |
| | 400 |
| 600 |
| | — |
| | — |
| | 600 |
|
| 6.600% Senior Notes due 2046 | | — |
| | — |
| | 1,100 |
| | 1,100 |
|
| WES 5.300% Notes due 2048 | | 700 |
| | — |
| | — |
| | 700 |
|
| WES 5.500% Notes due 2048 | | 350 |
| | — |
| | — |
| | 350 |
|
| 7.730% Debentures due 2096 | 61 |
| | 61 |
| — |
| | — |
| | 61 |
| | 61 |
|
| 7.500% Debentures due 2096 | 78 |
| | 78 |
| — |
| | — |
| | 78 |
| | 78 |
|
| 7.250% Debentures due 2096 | 49 |
| | 49 |
| — |
| | — |
| | 49 |
| | 49 |
|
| WES revolving credit facility | 300 |
| | 510 |
| |
| WES RCF | | 220 |
| | — |
| | — |
| | 220 |
|
| WGP RCF | | — |
| | 28 |
| | — |
| | 28 |
|
| Total borrowings at face value | $ | 17,312 |
| | $ | 16,687 |
| $ | 4,840 |
| | $ | 28 |
| | $ | 12,793 |
| | $ | 17,661 |
|
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 |
| |
Net unamortized discounts, premiums, and debt issuance costs (3) | | (53 | ) | | — |
| | (1,439 | ) | | (1,492 | ) |
Total borrowings (4) | | 4,787 |
| | 28 |
| | 11,354 |
| | 16,169 |
|
| Capital lease obligations | | — |
| | — |
| | 248 |
| | 248 |
|
| Less short-term debt | | — |
| | 28 |
| | 919 |
| | 947 |
|
| Total long-term debt | | $ | 4,787 |
| | $ | — |
| | $ | 10,683 |
| | $ | 15,470 |
|
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 13. Debt and Interest Expense (Continued) |
|
| | | | | | | | | | | | | | | |
| | December 31, 2017 |
| millions | WES |
| | WGP (1) |
| Anadarko (2) | | Anadarko Consolidated | |
| 7.050% Debentures due 2018 | $ | — |
| | $ | — |
| | $ | 114 |
| | $ | 114 |
|
| TEUs - senior amortizing notes due 2018 | — |
| | — |
| | 17 |
| | 17 |
|
| 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 |
|
| 4.850% Senior Notes due 2021 | — |
| | — |
| | 800 |
| | 800 |
|
| 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 |
| | — |
| | — |
| | 500 |
|
| WES 4.650% Senior Notes due 2026 | 500 |
| | — |
| | — |
| | 500 |
|
| 5.550% Senior Notes due 2026 | — |
| | — |
| | 1,100 |
| | 1,100 |
|
| 7.500% Debentures due 2026 | — |
| | — |
| | 112 |
| | 112 |
|
| 7.000% Debentures due 2027 | — |
| | — |
| | 48 |
| | 48 |
|
| 7.125% Debentures due 2027 | — |
| | — |
| | 150 |
| | 150 |
|
| 6.625% Debentures due 2028 | — |
| | — |
| | 14 |
| | 14 |
|
| 7.150% Debentures due 2028 | — |
| | — |
| | 235 |
| | 235 |
|
| 7.200% Debentures due 2029 | — |
| | — |
| | 135 |
| | 135 |
|
| 7.950% Debentures due 2029 | — |
| | — |
| | 116 |
| | 116 |
|
| 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 | 600 |
| | — |
| | — |
| | 600 |
|
| 6.600% Senior Notes due 2046 | — |
| | — |
| | 1,100 |
| | 1,100 |
|
| 7.730% Debentures due 2096 | — |
| | — |
| | 61 |
| | 61 |
|
| 7.500% Debentures due 2096 | — |
| | — |
| | 78 |
| | 78 |
|
| 7.250% Debentures due 2096 | — |
| | — |
| | 49 |
| | 49 |
|
| WES RCF | 370 |
| | — |
| | — |
| | 370 |
|
| WGP RCF | — |
| | 28 |
| | — |
| | 28 |
|
| Total borrowings at face value | $ | 3,490 |
| | $ | 28 |
| | $ | 13,514 |
| | $ | 17,032 |
|
Net unamortized discounts, premiums, and debt issuance costs (3) | (25 | ) | | — |
| | (1,549 | ) | | (1,574 | ) |
Total borrowings (4) | 3,465 |
| | 28 |
| | 11,965 |
| | 15,458 |
|
| Capital lease obligations | — |
| | — |
| | 231 |
| | 231 |
|
| Less short-term debt | — |
| | — |
| | 142 |
| | 142 |
|
| Total long-term debt | $ | 3,465 |
| | $ | 28 |
| | $ | 12,054 |
| | $ | 15,547 |
|
| |
(1) | Unamortized discounts and premiums are amortized over the term of the related debt.Excludes WES. |
| |
(2) | Excludes WES and WGP. |
| |
(3) | Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets. |
| |
(4) | The total long-term debt balanceCompany’s outstanding borrowings, except for WES was $2.7 billion at December 31, 2015, and $2.4 billion at December 31, 2014.borrowings under the WGP RCF, are senior unsecured. |
113124 | APC 2018 FORM 10-K
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
11. |
|
| 13. Debt and Interest Expense (Continued) |
In a 2006 private offering, Anadarko received Scheduled Maturities$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 aggregateTotal principal amount due at maturity of approximately $2.4 billion, reflecting a yielddebt maturities related to maturity of 5.24%. The Zero Coupons can be put to the Company in October of each year, in whole or in part,borrowings for the then-accreted value offive years ending December 31, 2023, excluding the outstanding Zero Coupons. The accreted valuepotential repayment of the outstanding Zero Coupons was $806 million at December 31, 2015. Anadarko’s Zero Coupons were classified as long-term debt onthat may be put by the Company’s Consolidated Balance Sheet at December 31, 2015, asholders to the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.annually, were as follows:
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). |
| | | | | | | | | | | | | | | |
| | Principal Amount of Debt Maturities |
| millions | WES |
| | WGP (1) |
| Anadarko (2) | | Anadarko Consolidated | |
| 2019 | $ | — |
| | $ | 28 |
| | $ | 900 |
| | $ | 928 |
|
| 2020 | — |
| | — |
| | — |
| | — |
|
| 2021 | 500 |
| | — |
| | 677 |
| | 1,177 |
|
| 2022 | 670 |
| | — |
| | — |
| | 670 |
|
| 2023 | 220 |
| | — |
| | — |
| | 220 |
|
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$16.8 billion at December 31, 2015,2018, and $17.4$17.7 billion at December 31, 2014.2017.
Debt ActivityAPC The following summarizes the Company’s debt activity:2018 FORM 10-K | 125
|
| | | | | |
| 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 repaymentsFINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
11. |
|
| 13. Debt and Interest Expense (Continued) |
Anadarko Revolving Credit FacilitiesDebt (Excluding WES and Commercial Paper ProgramWGP) In June 2014,December 2018, the Company purchased and retired $377 million of its $625 million 3.450% Senior Notes due 2024 and $123 million of its $800 million 4.850% Senior Notes due 2021 pursuant to a tender offer. The Company recognized a net gain of $7 million for the early retirement of these senior notes. The Company repaid $114 million of 7.050% Debentures at maturity in May 2018.
In a 2006 private offering, Anadarko entered intoreceived $500 million of loan proceeds upon issuing the Five-Year FacilityZero Coupons. The Zero Coupons mature in 2036 and have an aggregate principal amount due at maturity of approximately $2.3 billion, reflecting a $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility)yield to maturity of 5.24%. In January 2015, upon satisfaction of certain conditions, includingDecember 2018, the paymentCompany purchased and retired $36 million of the settlementaccreted value of its Zero Coupons due 2036 and recognized a loss of $3 million for the early retirement of these senior notes. This early retirement results in a reduction of $90 million of the $2.4 billion originally due at maturity in 2036. Anadarko’s 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, which, if put in whole, would be $942 million at the next put date in October 2019. None of the Zero Coupons were put to the Company in October 2018. The accreted value of the outstanding Zero Coupons was $905 million at December 31, 2018. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at December 31, 2018, as the Company has the ability and intent to refinance these obligations using long-term debt, should a put be exercised. Principal payments related to the Tronox Adversary Proceeding, these facilities replacedZero Coupons are reported in financing activities and interest accretion payments related to the $5.0 billion Facility. Zero Coupons are reported in operating activities on the Company’s Consolidated Statement of Cash Flows.
In December 2015,January 2018, the Company amended the Five-Year Facilityits $3.0 billion senior unsecured RCF to extend the maturity date to January 20212022 (APC RCF) and in January 2016, the Company replaced the 364-Day Facility with a newamended its $2.0 billion 364-day senior unsecured revolving facility on identical terms that will matureRCF to extend the maturity date to January 2019 (364-Day Facility). In December 2018, the Company amended its APC RCF to extend the maturity date to January 2023. The 364-Day Facility expired in 2017.January 2019.
Borrowings under the Five-Year FacilityAPC RCF and the 364-Day Facility (collectivity,(collectively, 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 FacilityAPC RCF 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 FacilityAPC RCF 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, 2015,2018, the Company had no outstanding borrowings under the Credit Facilities and was in compliance with all covenants contained therein.covenants.
In January 2015, the Company initiated a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Five-Year Facility.notes. The maturities of the commercial paper notes may vary, but may not exceed 397 days. The commercial paper notes are sold under customary terms inAs a result of Moody’s credit rating on Anadarko, the Company’s access to the commercial paper market has been limited. The Company has not issued commercial paper notes since the downgrade 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 tohad no outstanding borrowings under 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.2018.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 13. Debt and Interest Expense (Continued) |
WES Borrowingsand WGP Debt In February 2014,2018, WES amended its RCF to extend the maturity date from February 2020 to February 2023 and restated its then-existing $800 million senior unsecured revolving credit facility by entering into a five-year, $1.2expand the borrowing capacity to $1.5 billion senior unsecured revolving credit facility maturing in February 2019 (RCF), which(WES RCF). As part of the amendment, the WES RCF is expandable to a maximum of $1.5$2.0 billion. In December 2018, WES entered into an amendment to extend the maturity date from February 2023 to February 2024 effective on February 15, 2019 and to expand the borrowing capacity to $2.0 billion, while leaving the $500 million accordion feature unexercised. Expansion of the borrowing capacity is subject to the completion of the WES Merger anticipated in the first quarter of 2019. See Note 24—Noncontrolling Interests for additional information related to the WES Merger. Borrowings under the WES 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. During 2018, WES borrowed $540 million under its RCF, which was used for general partnership purposes, and made repayments of $690 million. At December 31, 2015,2018, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $300$220 million at an interest rate of 1.73%3.74%, and hadoutstanding letters of credit of $5 million, available borrowing capacity of approximately $894$1.3 billion, and was in compliance with all covenants.
In March 2018, WES completed a public offering of $400 million ($1.2 billion capacity, less $300aggregate principal amount of 4.500% Senior Notes due March 2028 and a public offering of $700 million aggregate principal amount of 5.300% Senior Notes due March 2048. Net proceeds from the public offerings were used to repay amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.
In August 2018, WES completed a public offering of $400 million aggregate principal amount of 4.750% Senior Notes due August 2028 and a public offering of $350 million aggregate principal amount of 5.500% Senior Notes due August 2048. The net proceeds from the public offerings were used to repay the maturing $350 million of 2.600% Senior Notes due August 2018, and amounts outstanding under the WES RCF. The remaining net proceeds were used for general partnership purposes, including to fund capital expenditures.
In December 2018, WES entered into a $2.0 billion 364-day senior unsecured credit agreement (WES 364-Day Facility), the proceeds of which will be used to fund substantially all of the cash portion of the consideration under the WES midstream asset contribution and sale and the payment of related transaction costs. The WES 364-Day Facility will mature on the day prior to the one-year anniversary of the completion of the WES Merger, and will bear interest at LIBOR, plus applicable margins ranging from 1.000% to 1.625%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, in each case as defined in the WES 364-Day Facility and plus applicable margins currently ranging from zero to 0.625%, based upon WES’s senior unsecured debt rating. WES is also required to pay a ticking fee of 0.175% on the commitment amount beginning 90 days after the effective date of the credit agreement through the date of funding under the WES 364-Day Facility. The WES 364-Day Facility contains covenants and customary events of default that are substantially similar to the WES RCF. Additionally, funding of the WES 364-Day Facility is conditioned upon the completion of the WES Merger, and net cash proceeds received from future asset sales and debt or equity offerings by WES must be used to repay amounts outstanding under the WES 364-Day Facility. See Note 24—Noncontrolling Interests for additional information related to the WES Merger. During 2016, WGP had a $250 million senior secured RCF that matures in March 2019 and was expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions (WGP RCF). In February 2018, WGP voluntarily reduced the aggregate commitments of the lenders under the WGP RCF from $250 million to $35 million. In December 2018, the WGP RCF was amended to extend the maturity date from March 2019 to the earlier of June 2019 or three business days following the completion of the WES Merger. See Note 24—Noncontrolling Interests for additional information related to the WES Merger. Obligations under the WGP RCF are secured by a first priority lien on all of WGP’s assets (not including the consolidated assets of WES) as well as all equity interests owned by WGP. Borrowings under the WGP RCF bear interest at LIBOR (with a floor of 0%), plus applicable margins ranging from 2.00% to 2.75% depending on WGP’s consolidated leverage ratio, or at a base rate equal to the greatest of (i) the prime rate, (ii) the federal funds rate plus 0.50%, or (iii) LIBOR plus 1.00%, in each case plus applicable margins ranging from 1.00% to 1.75% based upon WGP’s consolidated leverage ratio. At December 31, 2018, WGP had outstanding borrowings of $28 million at an interest rate of 4.53% classified as short-term debt on the Company’s Consolidated Balance Sheet, available borrowing capacity of $7 million, and $6 million of outstanding letters of credit).was in compliance with all covenants.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
11. |
|
| 13. Debt and Interest Expense (Continued) |
Scheduled Maturities Capital Lease ObligationsTotal principal amountConstruction of debt maturitiesa FPSO for the fiveCompany’s TEN field in Ghana commenced in 2013. The Company recognized an asset and related obligation for its approximate 19% nonoperated participating interest share during the construction period. Upon completion of construction in the third quarter of 2016, the Company reported the asset and related obligation as a capital lease of $225 million for the Company’s proportionate share of the fair value of the FPSO. The FPSO lease provides for an initial term of 10 years endingwith annual renewal periods for an additional 10 years, annual purchase options that decrease over time, and no residual value guarantees. The capital lease asset is being depreciated over the estimated proved reserves of the TEN field using the UOP method, with the associated depreciation included in DD&A in the Company’s Consolidated Statement of Income. The accumulated depreciation of the FPSO capital lease asset was $72 million at December 31, 2020, excluding2018, and $41 million at December 31, 2017. The capital lease obligation is being accreted to the potential repaymentpresent value of the outstanding Zero Coupons that may be put byminimum lease payments using the holderseffective interest method. The Company made capital lease payments of $46 million in 2018 and $44 million in 2017.
At December 31, 2018, future minimum lease payments related to the Company annually, were as follows:Company’s capital leases were:
| | | millions | Principal Amount of Debt Maturities | |
| 2016 | $ | 2,033 |
| |
| 2017 | 2,034 |
| |
| 2018 | 482 |
| |
| 2019 | 1,200 |
| $ | 58 |
|
| 2020 | — |
| 50 |
|
| 2021 | | 48 |
|
| 2022 | | 45 |
|
| 2023 | | 43 |
|
| Thereafter | | 323 |
|
| Total future minimum lease payments | | $ | 567 |
|
| Less portion representing imputed interest | | 319 |
|
| Capital lease obligations | | $ | 248 |
|
Interest ExpenseThe following summarizes interest expense for the years ended December 31:
| | | millions | 2015 | | 2014 | | 2013 | 2018 |
| | 2017 |
| | 2016 |
|
| Debt and other | $ | 989 |
| | $ | 973 |
| | $ | 949 |
| $ | 1,028 |
| | $ | 1,003 |
| | $ | 1,022 |
|
| Capitalized interest | (164 | ) | | (201 | ) | | (263 | ) | (81 | ) | | (71 | ) | | (132 | ) |
| Total interest expense | $ | 825 |
| | $ | 772 |
| | $ | 686 |
| $ | 947 |
| | $ | 932 |
| | $ | 890 |
|
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
The Tax Reform Legislation enacted on December 22, 2017, reduced the U.S. corporate tax rate from 35% to 21%. Upon enactment, the Company recognized a provisional and one-time deferred tax benefit of $1.2 billion, inclusive of a $236 million increase to the Company’s valuation allowance on its foreign tax credit carryforwards, due to the remeasurement of its U.S. deferred tax assets and liabilities based on the rate reduction. During 2018, the Company completed the accounting for the income tax effects related to the adoption of the Tax Reform Legislation before the end of the measurement period. The Company revised the provisional amount recorded in 2017 and recognized an additional current tax benefit of $26 million, primarily related to the acceleration of pension deductions into 2017. This benefit was offset by deferred tax expense of $121 million, primarily related to additional valuation allowance on the Company’s foreign tax credit carryforwards.
The following summarizes components of income tax expense (benefit) for the years ended December 31:
| | | millions | 2015 | | 2014 | | 2013 | 2018 |
| | 2017 |
| | 2016 |
|
| Current | | | | | | | | | | |
| Federal | $ | (177 | ) | | $ | 188 |
| | $ | 113 |
| $ | 14 |
| | $ | 236 |
| | $ | (140 | ) |
| State | (18 | ) | | 2 |
| | 42 |
| (1 | ) | | 48 |
| | (1 | ) |
| Foreign | 495 |
| | 1,574 |
| | 873 |
| 595 |
| | 414 |
| | 378 |
|
| | 300 |
| | 1,764 |
| | 1,028 |
| |
| Total current tax expense (benefit) | | 608 |
| | 698 |
| | 237 |
|
| Deferred | | | | | | | | | | |
| Federal | (2,929 | ) | | (389 | ) | | 94 |
| 150 |
| | (2,082 | ) | | (1,020 | ) |
| State | (145 | ) | | 27 |
| | (9 | ) | (26 | ) | | (17 | ) | | (148 | ) |
| Foreign | (103 | ) | | 215 |
| | 52 |
| 1 |
| | (76 | ) | | (90 | ) |
| | (3,177 | ) | | (147 | ) | | 137 |
| |
| Total deferred tax expense (benefit) | | 125 |
| | (2,175 | ) | | (1,258 | ) |
| Total income tax expense (benefit) | $ | (2,877 | ) | | $ | 1,617 |
| | $ | 1,165 |
| $ | 733 |
| | $ | (1,477 | ) | | $ | (1,021 | ) |
116APC 2018 FORM 10-K | 129
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
12. |
|
| 14. 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 | 2018 |
| | 2017 |
| | 2016 |
|
| Income (loss) before income taxes | | | | | | | | | | |
| Domestic | $ | (9,155 | ) | | $ | (3,564 | ) | | $ | 428 |
| $ | 492 |
| | $ | (1,322 | ) | | $ | (3,728 | ) |
| Foreign | (534 | ) | | 3,618 |
| | 1,678 |
| 993 |
| | (366 | ) | | (101 | ) |
| Total | $ | (9,689 | ) | | $ | 54 |
| | $ | 2,106 |
| $ | 1,485 |
| | $ | (1,688 | ) | | $ | (3,829 | ) |
| U.S. federal statutory tax rate | 35 | % | | 35 | % | | 35 | % | 21 | % | | 35 | % | | 35 | % |
| Tax computed at the U.S. federal statutory rate | $ | (3,391 | ) | | $ | 19 |
| | $ | 737 |
| $ | 312 |
| | $ | (591 | ) | | $ | (1,340 | ) |
| (Income) loss attributable to noncontrolling interests | | (29 | ) | | (85 | ) | | (92 | ) |
| Adjustments resulting from | | | | | | | | | | |
| State income taxes (net of federal income tax benefit) | (81 | ) | | (11 | ) | | 23 |
| (18 | ) | | 25 |
| | (108 | ) |
| U.S. federal tax reform | | 95 |
| | (1,168 | ) | | — |
|
| Tax impact from foreign operations | 299 |
| | 62 |
| | 204 |
| 181 |
| | 166 |
| | 80 |
|
| Non-deductible Algerian exceptional profits tax | 102 |
| | 193 |
| | 144 |
| 154 |
| | 110 |
| | 106 |
|
| Net changes in uncertain tax positions | 54 |
| | 1,427 |
| | (29 | ) | (29 | ) | | 90 |
| | 90 |
|
| 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 |
| | — |
| — |
| | 6 |
| | 205 |
|
| Other, net | — |
| | (12 | ) | | 22 |
| 67 |
| | (30 | ) | | 38 |
|
| Total income tax expense (benefit) | $ | (2,877 | ) | | $ | 1,617 |
| | $ | 1,165 |
| $ | 733 |
| | $ | (1,477 | ) | | $ | (1,021 | ) |
| Effective tax rate | 30 | % | | 2,994 | % | | 55 | % | 49 | % | | 88 | % | | 27 | % |
The following summarizes components of total deferred taxes at December 31:
| | | millions | 2015 | | 2014 | 2018 |
| | 2017 |
|
| Federal | $ | (4,721 | ) | | $ | (7,649 | ) | $ | (1,972 | ) | | $ | (1,758 | ) |
| State, net of federal | (248 | ) | | (341 | ) | (176 | ) | | (200 | ) |
| Foreign | (431 | ) | | (537 | ) | (255 | ) | | (255 | ) |
Total deferred taxes | $ | (5,400 | ) | | $ | (8,527 | ) | $ | (2,403 | ) | | $ | (2,213 | ) |
| |
(1) | Net deferred tax assets related to Algeria of $34 million in 2018 and $21 million in 2017 are presented in other assets on the Company’s Consolidated Balance Sheet. |
117130 | APC 2018 FORM 10-K
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
12. |
|
| 14. 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 | 2018 |
| | 2017 |
|
| Deferred tax liabilities | | | | | | |
| Oil and gas exploration and development operations | $ | (5,643 | ) | | $ | (8,418 | ) | $ | (2,403 | ) | | $ | (2,622 | ) |
| Midstream and other depreciable properties | (1,049 | ) | | (1,611 | ) | (662 | ) | | (543 | ) |
| Mineral operations | (492 | ) | | (412 | ) | (238 | ) | | (312 | ) |
| Other | (470 | ) | | (351 | ) | (134 | ) | | (53 | ) |
| Gross long-term deferred tax liabilities | (7,654 | ) | | (10,792 | ) | (3,437 | ) | | (3,530 | ) |
| Deferred tax assets | | | | | | |
| Oil and gas exploration and development costs | | 303 |
| | 309 |
|
| Foreign and state net operating loss carryforwards | 586 |
| | 558 |
| 445 |
| | 562 |
|
| U.S. foreign tax credit carryforwards | 1,254 |
| | 166 |
| 2,665 |
| | 2,685 |
|
| Compensation and benefit plans | 615 |
| | 701 |
| 301 |
| | 365 |
|
| Mark to market on derivatives | 441 |
| | 354 |
| |
| Settlement agreement related to the Tronox Adversary Proceeding | — |
| | 590 |
| |
| Other | 761 |
| | 760 |
| 308 |
| | 420 |
|
| Gross long-term deferred tax assets | 3,657 |
| | 3,129 |
| 4,022 |
| | 4,341 |
|
| Valuation allowances on deferred tax assets not expected to be realized | (1,403 | ) | | (864 | ) | (2,988 | ) | | (3,024 | ) |
| Net long-term deferred tax assets | 2,254 |
| | 2,265 |
| 1,034 |
| | 1,317 |
|
| Total deferred taxes | $ | (5,400 | ) | | $ | (8,527 | ) | $ | (2,403 | ) | | $ | (2,213 | ) |
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 | 2018 |
| | 2017 |
| | 2016 |
|
| Balance at January 1 | $ | (864 | ) | | $ | (818 | ) | | $ | (922 | ) | $ | (3,024 | ) | | $ | (1,755 | ) | | $ | (1,403 | ) |
| Changes due to U.S. foreign tax credits | (384 | ) | | 11 |
| | 58 |
| (50 | ) | | (1,287 | ) | | (477 | ) |
| Changes due to foreign and state net operating loss carryforwards | 10 |
| | 64 |
| | (57 | ) | 72 |
| | 75 |
| | 13 |
|
| Changes due to foreign capitalized costs | (165 | ) | | (121 | ) | | 103 |
| 14 |
| | (57 | ) | | 112 |
|
| Balance at December 31 | $ | (1,403 | ) | | $ | (864 | ) | | $ | (818 | ) | $ | (2,988 | ) | | $ | (3,024 | ) | | $ | (1,755 | ) |
Tax carryforwards available, for use on future income tax returns, prior to valuation allowance, at December 31, 2015,2018, were as follows:
| | | millions | Domestic | | Foreign | | Expiration | Domestic |
| | Foreign |
| Expiration |
Net operating loss—state (1) | | $ | 4,250 |
| | $ | — |
| 2019-2038 |
| Net operating loss—foreign | $ | — |
| | $ | 1,264 |
| | 2016 - Indefinite | $ | — |
| | $ | 820 |
| 2019-Indefinite |
| Net operating loss—state | $ | 4,762 |
| | $ | — |
| | 2016-2035 | |
Foreign tax credits | $ | 1,254 |
| | $ | — |
| | 2023-2026 | $ | 2,665 |
| | $ | — |
| 2023-2028 |
| Texas margins tax credit | $ | 33 |
| | $ | — |
| | 2026 | $ | 27 |
| | $ | — |
| 2026 |
| |
(1) | Net of $711 million uncertain tax position at December 31, 2018. |
| |
(2) | Net of $378 million uncertain tax position at December 31, 2018. |
118APC 2018 FORM 10-K | 131
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
12. |
|
| 14. Income Taxes (Continued) |
The following summarizes taxes receivable (payable) related to income tax expense (benefit) at December 31:
| | | millions | | | | | | | |
| Balance Sheet Classification | | 2015 | | 2014 | 2018 |
| | 2017 |
|
| Income taxes receivable | | | | | | | |
| Accounts receivable—other | | $ | 1,046 |
| | $ | 93 |
| $ | 46 |
| | $ | 53 |
|
| Other assets | | 61 |
| | 35 |
| 51 |
| | 101 |
|
| | | 1,107 |
| | 128 |
| 97 |
| | 154 |
|
| Income taxes (payable) | | | | | | | |
| Accrued expense | | (9 | ) | | (152 | ) | |
| Other current liabilities | | (167 | ) | | (71 | ) |
| Total net income taxes receivable (payable) | | $ | 1,098 |
| | $ | (24 | ) | $ | (70 | ) | | $ | 83 |
|
Changes in the balance of unrecognized tax benefits, excluding interest and penalties on uncertain tax positions, were as follows:
| | | | Assets (Liabilities) | Assets (Liabilities) |
| millions | 2015 | | 2014 | | 2013 | 2018 |
| | 2017 |
| | 2016 |
|
| Balance at January 1 | $ | (1,687 | ) | | $ | (147 | ) | | $ | (46 | ) | $ | (1,317 | ) | | $ | (1,456 | ) | | $ | (1,780 | ) |
| Increases related to prior-year tax positions | (99 | ) | | (11 | ) | | (54 | ) | (21 | ) | | (15 | ) | | (86 | ) |
| Decreases related to prior-year tax positions | 89 |
| | 39 |
| | 3 |
| 48 |
| | 214 |
| | 436 |
|
| Increases related to current-year tax positions | (263 | ) | | (1,568 | ) | | (72 | ) | — |
| | (72 | ) | | (26 | ) |
| Settlements | 180 |
| | — |
| | 5 |
| 1 |
| | 12 |
| | — |
|
| Lapse of statute of limitations | — |
| | — |
| | 17 |
| 2 |
| | — |
| | — |
|
| Balance at December 31 | $ | (1,780 | ) | | $ | (1,687 | ) | | $ | (147 | ) | $ | (1,287 | ) | | $ | (1,317 | ) | | $ | (1,456 | ) |
Included in the 2015 endingThe December 31, 2018 balance of unrecognized tax benefits presented above areincludes potential benefits of $1.756$1.24 billion, of which, if recognized, $1.337$1.26 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.income. Also included in the 2015 ending balance are benefits of $24$43 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, theThe Company had recordedrecognized a totalnet tax benefit of $576$346 million at December 31, 2018 and 2017, related to the Tronox-related contingent liability.deduction of its 2015 settlement payment for the Tronox Adversary Proceeding. This benefit is net of a $1.3 billion uncertain tax positionpositions of $1.2 billion at December 31, 2018 and 2017, due to the uncertainty related to the deductibility of the settlement payment. Due to the deduction of the settlement payment, the Company had a net operating loss carryback for 2015, which resulted in a tentative tax refund of $881 million in 2016. The IRS has audited this position and, in April 2018, issued a final notice of proposed adjustment denying the deductibility of the settlement payment. In September 2018, the Company received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting the Company’s refund claim. As a result, the Company filed a petition with the U.S. Tax Court to dispute the disallowances in November 2018, and pursuant to standard U.S. Tax Court procedures, the Company is a participantnot required to repay the $881 million refund to dispute the IRS’s position. Accordingly, the Company has not revised its estimate of the benefit that will ultimately be realized. After the case is tried and briefed in the U.S. Internal Revenue Service’s (IRS) Compliance Assurance Process forTax Court, the 2015 tax yearcourt will issue an opinion and has regular discussions withthen enter a decision. If the IRS concerning the Company’s tax position. DependingCompany does not prevail on the outcomeissue, the earliest date the Company might be required to repay the refund received, plus interest, would be 91 days after entry of the decision. At such discussions, ittime, the Company would reverse the portion of the $346 million net benefit previously recognized in its consolidated financial statements to the extent necessary to reflect the result of the Tax Court decision. It is reasonably possible that the amount of the uncertain tax position relatedand/or tax benefit could materially change as the Company asserts its position in the Tax Court proceedings. Although management cannot predict the timing of a final resolution of the Tax Court proceedings, the Company does not anticipate a decision to be entered within the settlement could change, perhaps materially. Seenext three years.
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 14. Income Taxes (Continued) |
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—18—Contingencies—Other Litigation. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by $400$70 million to $410$90 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 believebelieves that the final resolution of outstanding tax audits and litigation will not have a material adverse effect on the Company’s consolidated financial condition, results of operations, or cash flows.
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$95 million of interest related to uncertain tax positions at December 31, 2015,2018, and $9$86 million at December 31, 2014.2017. The Company recognized interest and penalties in income tax expense (benefit) of $2$9 million during 20152018 and $1$55 million during 2014.2017.
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 | 2008-20152013-2018 |
| Algeria | 2012-20152015-2018 |
| Ghana | 2006-20152015-2018 |
|
|
| 15. 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 | 2018 |
| | 2017 |
|
| Carrying amount of asset retirement obligations at January 1 | $ | 2,053 |
| | $ | 2,022 |
| |
| Carrying amount at January 1 | | $ | 2,794 |
| | $ | 2,931 |
|
| Liabilities acquired | | — |
| | 4 |
|
| Liabilities incurred | 104 |
| | 119 |
| 153 |
| | 191 |
|
| Property dispositions | (108 | ) | | (70 | ) | (99 | ) | | (154 | ) |
| Liabilities settled | (298 | ) | | (443 | ) | (274 | ) | | (135 | ) |
| Accretion expense | 102 |
| | 93 |
| 130 |
| | 144 |
|
| Revisions in estimated liabilities | 206 |
| | 332 |
| 395 |
| | (187 | ) |
| Carrying amount of asset retirement obligations at December 31 | $ | 2,059 |
| | $ | 2,053 |
| |
| Carrying amount at December 31 | | $ | 3,099 |
| | $ | 2,794 |
|
120APC 2018 FORM 10-K | 133
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
|
|
| 16. Conveyance of Future Hard-Minerals Royalty Revenues |
During the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to Financial Statementsa third party for $413 million, net of transaction costs. Such conveyance entitles the third party to receive up to $553 million in future royalty revenue over a period of not less than 10 years and not greater than 15 years. Additionally, such third party is entitled to receive 3% of the aggregate royalties earned during the first 10 years between $800 million and $900 million and 4% of the aggregate royalties earned during the first 10 years that exceed $900 million. Generally, such third party relies solely on the royalty payments to recover its investment and, as such, has the risk of the royalties not being sufficient to recover its investment over the term of the conveyance.
Proceeds from this transaction were accounted for as deferred revenues and are included in other current liabilities and other long-term liabilities - other on the Company’s Consolidated Balance Sheet. The deferred revenues will be amortized to other revenues, included in gains (losses) on divestitures and other, net, on a unit-of-revenue basis over the term of the agreement. Net proceeds received from the third party were reported in financing activities on the Company’s Consolidated Statement of Cash Flows. Semi-annual payments to the third party are scheduled on March 1 and September 1 of each year through March 1, 2026. The specified future amounts that the Company expects to pay and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the conveyance. Royalties received by Anadarko under this agreement are reported in operating activities on the Company’s Consolidated Statement of Cash Flows. The semi-annual payments to the third party, up to the aggregate amount of the $413 million net proceeds the Company received for the conveyance in the first quarter of 2016, are reported in financing activities on the Company’s Consolidated Statement of Cash Flows. Any additional payments to the third party are reported in operating activities on the Company’s Consolidated Statement of Cash Flows to offset the royalties received.
The Company amortized deferred revenues of $36 million in 2018, $38 million in 2017, and $37 million in 2016 as a result of this agreement. The Company made payments for royalties totaling $50 million in 2018 and 2017, and $25 million in 2016. The following summarizes the remaining amounts that the Company expects to pay, prior to the potential 3% to 4% of any excess described above:
|
| | | |
| millions | |
| 2019 | $ | 52 |
|
| 2020 | 57 |
|
| 2021 | 57 |
|
| 2022 | 58 |
|
| 2023 | 60 |
|
| Thereafter | 144 |
|
| Total | $ | 428 |
|
ANADARKO PETROLEUM CORPORATIONNOTES TO CONSOLIDATED |
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
Operating LeasesAt December 31, 2015,2018, the Company had $1.8 billion$262 million in long-term drilling rig commitments that satisfyare accounted for as operating lease criteria.leases. These drilling rig operating leases expire at various dates through 2021. The Company also had $329$392 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 2026.2033. Certain of these operating leases contain residual value guarantees at the end of the lease term totaling $81of $73 million at December 31, 2015. No2018. A $5 million liability has beenwas 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, 2015:2018:
| | | millions | | |
| 2016 | $ | 806 |
| |
| 2017 | 604 |
| |
| 2018 | 352 |
| |
| 2019 | 228 |
| $ | 264 |
|
| 2020 | 86 |
| 139 |
|
| Later years | 41 |
| |
| 2021 | | 57 |
|
| 2022 | | 35 |
|
| 2023 | | 24 |
|
| Thereafter | | 135 |
|
| Total future minimum lease payments | $ | 2,117 |
| $ | 654 |
|
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$209 million related to fivethree offshore drilling vessels, and $98$41 million related to certain contracts for U.S. onshore drilling rigs, and $12 million related to certain contracts for two international 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$74 million in 2015, $852018, $55 million in 2014,2017, and $119$73 million in 2013.2016. Total rent expense includesincluded contingent rent expense related to transportation and processing fees of $17$4 million in 2015, $222018, $3 million in 2014,2017, and $24$6 million in 2013.2016.
Other Commitments In the normal course of business, the CompanyAnadarko has various long-term contractual commitments pertaining to oil and natural-gas activities such as work-related commitments for drilling wells, obtaining and processing seismic data, and fulfilling rig commitments. Anadarko also enters into other contractualvarious processing, transportation, storage, and purchase agreements for processing, treating, transportation,to access markets and storage ofprovide flexibility to sell its oil, natural gas, and NGLs as well as for other oil and gas activities.in certain areas. These agreements expire at various dates through 2036. At December 31, 2015,2033. The following summarizes the gross aggregate future payments under these contracts totaledat December 31, 2018:
|
| | | |
| millions | |
| 2019 | $ | 1,147 |
|
| 2020 | 1,155 |
|
| 2021 | 993 |
|
| 2022 | 786 |
|
| 2023 | 646 |
|
| Thereafter | 1,498 |
|
Total (1) | $ | 6,225 |
|
| |
(1) | Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator. |
APC $10.1 billion2018 FORM 10-K , 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
15. Contingencies135
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
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 liabilitiesAs of $269 million at December 31, 2015, and $5.3 billion at December 31, 2014,2018, the Company had $33 million accrued 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.
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.
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.).
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.
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, 2015,2018, the deposit of $86$88 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 andappeal to the Brazilian Supreme Court have agreed to hearhas been stayed pending a decision in the case and the Company currently is awaiting the setting of initial hearing dates.Superior Court appeal.
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, 2015.2018. The Company continues to vigorously defend its tax position in the Brazilian courts.
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$109 million at December 31, 2015,2018, and $126$113 million at December 31, 2014.2017. The current portion of these amounts was included in accounts payableother current liabilities 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.
|
|
| 19. Restructuring Charges |
In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of its workforce with its expected future operating and capital plans. Employee notifications related to the workforce reduction program were completed by June 30, 2016. The Company is onerecognized $389 million of numerous parties previously notified by the California Departmentrestructuring charges, comprised 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$192 million in West Covina, California. While no agreement isG&A and $197 million 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 includedOther (income) expense, net, in the Company’s liability balance atConsolidated Statements of Income during the year ended December 31, 2015. The Company could incur additional obligations if any2016. All restructuring charges were recognized in 2016, with the exception 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$21 million, primarily related to this matter could change, perhaps materially, in the future.defined-benefit pension settlement expense, which was recognized during 2017 for lump-sum payments to terminated participants.
127136 | APC 2018 FORM 10-K
ANADARKO PETROLEUM CORPORATION |
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2015, 2014, AND 201316. |
|
| 20. 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, 20152018 and 2014,2017, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 20152018 and 2014:2017:
| | | | Pension Benefits | | Other Benefits | Pension Benefits | | Other Benefits |
| millions | 2015 | | 2014 | | 2015 | | 2014 | | 2018 |
| | 2017 |
| | | 2018 |
| | 2017 |
|
| Change in benefit obligation | | | | | | | | | | | | | | | |
| Benefit obligation at beginning of year | $ | 2,528 |
| | $ | 2,158 |
| | $ | 373 |
| | $ | 294 |
| | $ | 2,218 |
| | $ | 2,301 |
| | $ | 302 |
| | $ | 296 |
|
| Service cost | 118 |
| | 99 |
| | 9 |
| | 7 |
| | 90 |
| | 87 |
| | 1 |
| | 2 |
|
| Interest cost | 101 |
| | 99 |
| | 15 |
| | 15 |
| | 77 |
| | 84 |
| | 11 |
| | 12 |
|
| Plan amendments | — |
| | — |
| | (89 | ) | | — |
| |
| Actuarial (gain) loss | (115 | ) | | 337 |
| | (27 | ) | | 72 |
| | (176 | ) | | 107 |
| | (23 | ) | | 15 |
|
| Curtailments, settlements, and special termination benefits expense | | | 15 |
| | 23 |
| | — |
| | (1 | ) |
| Participant contributions | — |
| | 1 |
| | 5 |
| | 4 |
| | — |
| | — |
| | 7 |
| | 5 |
|
| Benefit payments | (194 | ) | | (159 | ) | | (20 | ) | | (19 | ) | | (268 | ) | | (396 | ) | | (25 | ) | | (27 | ) |
| Foreign-currency exchange-rate changes | (7 | ) | | (7 | ) | | — |
| | — |
| | (8 | ) | | 12 |
| | — |
| | — |
|
Benefit obligation at end of year (1) | $ | 2,431 |
| | $ | 2,528 |
| | $ | 266 |
| | $ | 373 |
| | $ | 1,948 |
| | $ | 2,218 |
| | $ | 273 |
| | $ | 302 |
|
| Change in plan assets | | | | | | | | | | | | | | | |
| Fair value of plan assets at beginning of year | $ | 1,818 |
| | $ | 1,754 |
| | $ | — |
| | $ | — |
| | $ | 1,424 |
| | $ | 1,340 |
| | $ | — |
| | $ | — |
|
| Actual return on plan assets | 16 |
| | 111 |
| | — |
| | — |
| | (57 | ) | | 209 |
| | — |
| | — |
|
| Employer contributions | 43 |
| | 121 |
| | 15 |
| | 15 |
| | 225 |
| | 254 |
| | 19 |
| | 22 |
|
| Participant contributions | — |
| | 1 |
| | 5 |
| | 4 |
| | — |
| | — |
| | 7 |
| | 5 |
|
| Benefit payments | (194 | ) | | (159 | ) | | (20 | ) | | (19 | ) | |
| Benefits paid related to plan settlements | | | (212 | ) | | (337 | ) | | (1 | ) | | (3 | ) |
| Benefit payments, other | | | (56 | ) | | (59 | ) | | (25 | ) | | (24 | ) |
| Foreign-currency exchange-rate changes | (9 | ) | | (10 | ) | | — |
| | — |
| | (10 | ) | | 17 |
| | — |
| | — |
|
| Fair value of plan assets at end of year | $ | 1,674 |
| | $ | 1,818 |
| | $ | — |
| | $ | — |
| | $ | 1,314 |
| | $ | 1,424 |
| | $ | — |
| | $ | — |
|
| | | | | | | | | |
| Funded status of the plans at end of year | $ | (757 | ) | | $ | (710 | ) | | $ | (266 | ) | | $ | (373 | ) | | $ | (634 | ) | | $ | (794 | ) | | $ | (273 | ) | | $ | (302 | ) |
| | | | | | | | | |
| Total recognized amounts in the balance sheet consist of |
|
|
|
|
|
|
| |
| Amounts recognized on the balance sheet | | |
| |
| |
| |
|
| Other assets | $ | 41 |
|
| $ | 41 |
|
| $ | — |
|
| $ | — |
| | $ | 63 |
| | $ | 58 |
| | $ | — |
| | $ | — |
|
| Accrued expenses | (24 | ) |
| (24 | ) |
| (16 | ) |
| (15 | ) | |
| Other current liabilities | | | (42 | ) | | (16 | ) | | (21 | ) | | (21 | ) |
| Other long-term liabilities—other | (774 | ) |
| (727 | ) |
| (250 | ) |
| (358 | ) | | (655 | ) | | (836 | ) | | (252 | ) | | (281 | ) |
| Total | $ | (757 | ) |
| $ | (710 | ) |
| $ | (266 | ) |
| $ | (373 | ) | | $ | (634 | ) | | $ | (794 | ) | | $ | (273 | ) | | $ | (302 | ) |
| | | | | | | | | |
| Total recognized amounts in accumulated other comprehensive income consist of |
|
|
|
|
|
|
| |
| Prior service cost (credit) | $ | (1 | ) |
| $ | (1 | ) |
| $ | (84 | ) |
| $ | 2 |
| |
| Amounts recognized in accumulated other comprehensive income | | |
| |
| |
| |
|
| Prior service (credit) cost | | | $ | 1 |
| | $ | — |
| | $ | (2 | ) | | $ | (26 | ) |
| Net actuarial (gain) loss | 655 |
|
| 740 |
|
| (25 | ) |
| 1 |
| | 399 |
| | 501 |
| | (9 | ) | | 14 |
|
| Total | $ | 654 |
|
| $ | 739 |
|
| $ | (109 | ) |
| $ | 3 |
| | $ | 400 |
| | $ | 501 |
| | $ | (11 | ) | | $ | (12 | ) |
| |
(1) | The accumulated benefit obligation for all defined-benefit pension plans was $2.1$1.6 billion at both December 31, 20152018 and $1.9 billion at December 31, 2014. 2017. |
128APC 2018 FORM 10-K | 137
|
| | |
| FINANCIAL STATEMENTS FOOTNOTES | |
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
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:
