UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ X ] ☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31,June 30, 2019
or
[ ]☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period fromto
Commission File No. 1-8968
(Exact name of registrant as specified in its charter)
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| Delaware | | 76-0146568 |
| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
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| 1201 Lake Robbins Drive, The Woodlands, Texas | | 77380-1046 |
| (Address of principal executive offices) | | (Zip Code) |
Registrant’s telephone number, including area code (832) (832) 636-1000
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | Trading symbol | Name of each exchange on which registered |
| Common Stock, par value $0.10 per share | APC | New York Stock Exchange |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ No ¨☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yesþ No ¨☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. þ
Large accelerated filerþ Accelerated filer ¨☐ Non-accelerated filer ¨☐ Smaller reporting company ¨☐ Emerging growth company ¨☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨☐ No þ
Securities registered pursuant to Section 12(b)The number of shares outstanding of the Act:Company’s common stock at July 19, 2019, was 502,453,426.
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| | | |
Title of each class | Trading symbol | Name of each exchange
on which registered
| Number of shares outstanding of the Company’s common stock at May 3, 2019 |
Common Stock, par value $0.10 per share | APC | New York Stock Exchange | 502,118,789 |
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| TABLE OF CONTENTS | Page |
| PART I |
| Item 1. | | |
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| Item 2. | | |
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| Item 3. | | |
| Item 4. | | |
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| Item 1. | | |
| Item 1A. | | |
| Item 2. | | |
| Item 6. | | |
COMMONLY USED TERMS AND DEFINITIONS
Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. In addition, the following company or industry-specific terms and abbreviations are used throughout this report:
364-Day Facility - Anadarko’s $2.0 billion 364-day senior unsecured RCF that expired in January 2019
APC RCF - Anadarko’s $3.0 billion senior unsecured RCF
ASR Agreement - An accelerated share-repurchase agreement with an investment bank to repurchase the Company’s common stock
ASU - Accounting Standards Update
Bcf - Billion cubic feet
Board - The Board of Directors of Anadarko
BOE - Barrels of oil equivalent
Chevron - Chevron Corporation
Chevron Merger - Chevron’s acquisition by merger of Anadarko pursuant to, and subject to the conditions of, the Chevron Merger Agreement
Chevron Merger Agreement -Agreement and Plan of Merger, dated as of April 11, 2019, by and among Chevron, Corporation, Justify Merger Sub 1 Inc., Justify Merger Sub 2 Inc. and Anadarko
Chevron Merger Termination Fee - The $1.0 billion termination fee paid to Chevron pursuant to the terms of the Chevron Merger Agreement
DD&A - Depreciation, depletion, and amortization
DJ - Denver-Julesberg
DJ Basin Complex - The Platte Valley system, Wattenberg system, Lancaster plant, and Wattenberg processing plant
FID- Final investment decision
Fitch- Fitch Ratings
FPSO - Floating production, storage, and offloading unit
G&A - General and administrative expenses
IPO - Initial public offering
IRS - U.S. Internal Revenue Service
LIBOR - London Interbank Offered Rate
LNG - Liquefied natural gas
LPG - Liquefied petroleum gas
MBbls/d - Thousand barrels per day
MBOE/d- Thousand barrels of oil equivalent per day
Mcf - Thousand cubic feet
MMBbls- Million barrels
MMBOE- Million barrels of oil equivalent
MMcf/d- Million cubic feet per day
Moody’s - Moody’s Investors Service
MTPA-Million tonnes per annum
NGL or NGLs - Natural-gas liquids
NYMEX- New York Mercantile Exchange
NYSE- New York Stock Exchange
Oil-Includes crude oil and condensate
Occidental - Occidental Petroleum Corporation
Occidental ProposalMerger - On April 24, 2019, Occidental announced a proposalOccidental’s acquisition by merger of Anadarko pursuant to, acquire Anadarko and further revised its proposal on May 5, 2019. All references hereinsubject to the Occidental Proposal refer toconditions of, the Occidental ProposalMerger Agreement
Occidental Merger Agreement - Agreement and Plan of Merger, dated as revisedof May 9, 2019, by and received byamong Occidental, Baseball Merger Sub 1, Inc. and Anadarko on May 5, 2019.
RCF - Revolving credit facility
ROU - Right-of-use
ROU - Right-of-use
S&P - Standard and Poor’s
Share-Repurchase Program - A program authorizing the repurchase of Anadarko’s common stock
TEN - Tweneboa/Enyenra/Ntomme
TEU or TEUs - Tangible equity units
Tronox - Tronox Incorporated
VIE or VIEs- Variable interest entity
WES- Western Midstream Partners, LP, a publicly traded limited partnership, is a consolidated subsidiary of Anadarko, with its common units traded on the NYSE under ticker symbol “WES”. WES consolidates Western Midstream Operating, LP. Prior to February 28, 2019, WES was known as Western Gas Equity Partners, LP, and its common units traded on the NYSE under ticker symbol “WGP”.
WES 364-Day Facility - WES Operating’s $2.0 billion 364-day senior unsecured credit facility
WES Merger - A merger, which was completed on February 28, 2019, whereby a wholly owned subsidiary of WES merged with and into WES Operating.
WES Operating - Western Midstream Operating, LP, a Delaware limited partnership in which WES holds (a) a 98% limited partner interest and (b) the entire non-economic general partner interest through its ownership of WES Operating’s sole general partner. Prior to February 28, 2019, WES Operating was known as Western Gas Partners, LP, and its common units traded on the NYSE under ticker symbol “WES”. Upon completion of the WES Merger, WES Operating’s common units ceased trading on the NYSE.
WES RCF - WES Operating’s $2.0 billion senior unsecured RCF
WES Term Loan Facility - WES Operating’s senior unsecured credit facility, previously referred to as the WES 364-Day Facility prior to the extension of the maturity date and increase in borrowing capacity effective July 1, 2019.
West Texas Complex - The DBM Complex and DBJV and Haley systems, all of which were combined into a single complex effective January 1, 2018.
WGP - Western Gas Equity Partners, LP, which changed its name to Western Midstream Partners, LP and began trading on the NYSE using the ticker symbol “WES” following the WES Merger.
WGP RCF- WGP’s $35 million senior secured RCF that matured in March 2019
WTI- West Texas Intermediate
Zero Coupons- Anadarko’s Zero-Coupon Senior Notes due 2036
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| CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS |
Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company has made in this Form 10-Q, and may from time to time make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include, among other things, information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, matters related to the ChevronOccidental Merger Agreement, and the Occidental Proposal, and also include those statements preceded by, followed by, or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” “would,” “will,” “potential,” “continue,” “forecast,” “future,” “likely,” “outlook,” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will be realized. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.
These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:
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| – | the Company’s assumptions about energy markets |
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| – | production and sales volume levels |
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| – | levels of oil, natural-gas, and NGL reserves |
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| – | availability of capital resources, levels of capital expenditures, and other contractual obligations |
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| – | supply and demand for, the price of, and the commercialization and transporting of oil, natural gas, NGLs, and other products or services |
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| – | volatility in the commodity-futures market |
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| – | availability of goods and services, including unexpected changes in costs |
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| – | drilling and other operational risks |
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| – | processing volume, pipeline throughput, and produced water disposal |
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| – | general economic conditions, nationally, internationally, or in the jurisdictions in which the Company is, or in the future may be, doing business |
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| – | the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those necessary for drilling and/or development projects |
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| – | legislative or regulatory changes, including changes relating to hydraulic fracturing or other oil and natural-gas operations; retroactive royalty or production tax regimes; deepwater and onshore drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation, including regulations related to climate change; environmental risks; and liability under international, provincial, federal, regional, state, tribal, local, and foreign environmental laws and regulations |
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| – | civil or political unrest or acts of terrorism in a region or country |
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| – | the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties |
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| – | volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-rate risk |
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| – | the impact of changes in the Company’s credit ratings |
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| – | the Company’s ability to successfully plan, secure additional government and partner approvals, enter into additional long-term sales contracts, make a final investment decision and the timing thereof, finance, build, and operate the necessary infrastructure and LNG park in Mozambique |
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| – | uncertainties and liabilities associated with acquired and divested properties and businesses |
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| – | disruptions in international oil and NGL cargo shipping activities |
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| – | physical, digital, internal, and external security breaches |
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| – | supply and demand, technological, political, governmental, and commercial conditions associated with long-term development and production projects in domestic and international locations |
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| – | the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board related to the Company’s operations in Colorado, and continued or additional disruptions in operations that may occur as the Company complies with regulatory orders or other state or local changes in laws or regulations in Colorado |
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| – | the completion of athe proposed merger transaction with Chevron or Occidental |
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| – | other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management |
Item 1. Financial Statements
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| millions except per-share amounts | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Revenues and Other | | | | | | | | | | |
| Oil sales | $ | 2,096 |
| | $ | 2,127 |
| $ | 2,470 |
| | $ | 2,265 |
| | $ | 4,566 |
| | $ | 4,392 |
|
| Natural-gas sales | 320 |
| | 247 |
| 205 |
| | 203 |
| | 525 |
| | 450 |
|
| Natural-gas liquids sales | 240 |
| | 292 |
| 216 |
| | 318 |
| | 456 |
| | 610 |
|
| Gathering, processing, and marketing sales | 470 |
| | 360 |
| 465 |
| | 382 |
| | 935 |
| | 742 |
|
| Gains (losses) on divestitures and other, net | 92 |
| | 19 |
| 86 |
| | 123 |
| | 178 |
| | 142 |
|
| Total | 3,218 |
| | 3,045 |
| 3,442 |
| | 3,291 |
| | 6,660 |
| | 6,336 |
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| Costs and Expenses | | | | | | | | | | |
| Oil and gas operating | 289 |
| | 276 |
| 310 |
| | 275 |
| | 599 |
| | 551 |
|
| Oil and gas transportation | 222 |
| | 196 |
| 222 |
| | 209 |
| | 444 |
| | 405 |
|
| Exploration | 49 |
| | 168 |
| 90 |
| | 94 |
| | 139 |
| | 262 |
|
| Gathering, processing, and marketing | 256 |
| | 237 |
| 274 |
| | 252 |
| | 530 |
| | 489 |
|
| General and administrative | 267 |
| | 278 |
| 368 |
| | 288 |
| | 635 |
| | 566 |
|
| Merger transaction costs | | 1,042 |
| | — |
| | 1,042 |
| | — |
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| Depreciation, depletion, and amortization | 1,081 |
| | 990 |
| 1,161 |
| | 1,003 |
| | 2,242 |
| | 1,993 |
|
| Production, property, and other taxes | 199 |
| | 190 |
| 182 |
| | 201 |
| | 381 |
| | 391 |
|
| Impairments | — |
| | 19 |
| — |
| | 128 |
| | — |
| | 147 |
|
| Other operating expense | 21 |
| | 140 |
| 8 |
| | 22 |
| | 29 |
| | 162 |
|
| Total | 2,384 |
| | 2,494 |
| 3,657 |
| | 2,472 |
| | 6,041 |
| | 4,966 |
|
| Operating Income (Loss) | 834 |
| | 551 |
| (215 | ) | | 819 |
| | 619 |
| | 1,370 |
|
| Other (Income) Expense | | | | | | | | | | |
| Interest expense | 253 |
| | 228 |
| 249 |
| | 237 |
| | 502 |
| | 465 |
|
| (Gains) losses on derivatives, net | 313 |
| | 35 |
| 254 |
| | 436 |
| | 567 |
| | 471 |
|
| Other (income) expense, net | 6 |
| | (12 | ) | 18 |
| | 4 |
| | 24 |
| | (8 | ) |
| Total | 572 |
| | 251 |
| 521 |
| | 677 |
| | 1,093 |
| | 928 |
|
| Income (Loss) Before Income Taxes | 262 |
| | 300 |
| (736 | ) | | 142 |
| | (474 | ) | | 442 |
|
| Income tax expense (benefit) | 166 |
| | 126 |
| 209 |
| | 125 |
| | 375 |
| | 251 |
|
| Net Income (Loss) | 96 |
| | 174 |
| (945 | ) | | 17 |
| | (849 | ) | | 191 |
|
| Net income (loss) attributable to noncontrolling interests | 111 |
| | 53 |
| 80 |
| | (12 | ) | | 191 |
| | 41 |
|
| Net Income (Loss) Attributable to Common Stockholders | $ | (15 | ) | | $ | 121 |
| $ | (1,025 | ) | | $ | 29 |
| | $ | (1,040 | ) | | $ | 150 |
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| | | | | | | | | | | |
| Per Common Share | | | | | | | | | | |
| Net income (loss) attributable to common stockholders—basic | $ | (0.03 | ) | | $ | 0.23 |
| $ | (2.09 | ) | | $ | 0.05 |
| | $ | (2.13 | ) | | $ | 0.28 |
|
| Net income (loss) attributable to common stockholders—diluted | $ | (0.03 | ) | | $ | 0.22 |
| $ | (2.09 | ) | | $ | 0.05 |
| | $ | (2.13 | ) | | $ | 0.28 |
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| Average Number of Common Shares Outstanding—Basic | 490 |
| | 518 |
| 491 |
| | 504 |
| | 491 |
| | 511 |
|
| Average Number of Common Shares Outstanding—Diluted | 490 |
| | 519 |
| 491 |
| | 505 |
| | 491 |
| | 512 |
|
See accompanying Notes to Consolidated Financial Statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
|
| | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
| millions | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Net Income (Loss) | $ | (945 | ) | | $ | 17 |
| | $ | (849 | ) | | $ | 191 |
|
| Other Comprehensive Income (Loss) | | | | | | | |
| Adjustments for derivative instruments | | | | | | | |
| Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | — |
| | — |
| | 1 |
| | 1 |
|
| Total adjustments for derivative instruments, net of taxes | — |
| | — |
| | 1 |
| | 1 |
|
| Adjustments for pension and other postretirement plans | | | | | | | |
| Net gain (loss) incurred during period | (80 | ) | | — |
| | (80 | ) | | — |
|
| Income taxes on net gain (loss) incurred during period | 18 |
| | — |
| | 18 |
| | — |
|
| Amortization of net actuarial (gain) loss to other (income) expense, net | 16 |
| | 6 |
| | 24 |
| | 13 |
|
| Income taxes on amortization of net actuarial (gain) loss | (4 | ) | | (1 | ) | | (6 | ) | | (3 | ) |
| Amortization of net prior service (credit) cost to other (income) expense, net | — |
| | (6 | ) | | (1 | ) | | (12 | ) |
| Income taxes on amortization of net prior service (credit) cost | — |
| | 1 |
| | — |
| | 2 |
|
| Total adjustments for pension and other postretirement plans, net of taxes | (50 | ) | | — |
| | (45 | ) | | — |
|
| Total | (50 | ) | | — |
| | (44 | ) | | 1 |
|
| Comprehensive Income (Loss) | (995 | ) | | 17 |
| | (893 | ) | | 192 |
|
| Comprehensive income (loss) attributable to noncontrolling interests | 80 |
| | (12 | ) | | 191 |
| | 41 |
|
| Comprehensive Income (Loss) Attributable to Common Stockholders | $ | (1,075 | ) | | $ | 29 |
| | $ | (1,084 | ) | | $ | 151 |
|
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| | | | | | | |
| | Three Months Ended |
| | March 31, |
| millions | 2019 |
| | 2018 |
|
| Net Income (Loss) | $ | 96 |
| | $ | 174 |
|
| Other Comprehensive Income (Loss) | | | |
| Adjustments for derivative instruments | | | |
| Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net | 1 |
| | 1 |
|
| Total adjustments for derivative instruments, net of taxes | 1 |
| | 1 |
|
| Adjustments for pension and other postretirement plans | | | |
| Amortization of net actuarial (gain) loss to other (income) expense, net | 8 |
| | 7 |
|
| Income taxes on amortization of net actuarial (gain) loss | (2 | ) | | (2 | ) |
| Amortization of net prior service (credit) cost to other (income) expense, net | (1 | ) | | (6 | ) |
| Income taxes on amortization of net prior service (credit) cost | — |
| | 1 |
|
| Total adjustments for pension and other postretirement plans, net of taxes | 5 |
| | — |
|
| Total | 6 |
| | 1 |
|
| Comprehensive Income (Loss) | 102 |
| | 175 |
|
| Comprehensive income (loss) attributable to noncontrolling interests | 111 |
| | 53 |
|
| Comprehensive Income (Loss) Attributable to Common Stockholders | $ | (9 | ) | | $ | 122 |
|
See accompanying Notes to Consolidated Financial Statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | March 31, |
| | December 31, |
| June 30, |
| | December 31, |
|
| millions except per-share amounts | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
|
| ASSETS | | | | | | |
| Current Assets | | | | | | |
| Cash and cash equivalents ($100 and $92 related to VIEs) | $ | 2,026 |
| | $ | 1,295 |
| |
| Cash and cash equivalents ($96 and $92 related to VIEs) | | $ | 1,394 |
| | $ | 1,295 |
|
| Accounts receivable (net of allowance of $11 and $13) | | | | | | |
| Customers ($138 and $138 related to VIEs) | 1,553 |
| | 1,491 |
| |
| Customers ($118 and $138 related to VIEs) | | 1,195 |
| | 1,491 |
|
| Others | 512 |
| | 535 |
| 584 |
| | 535 |
|
| Other current assets | 338 |
| | 474 |
| 298 |
| | 474 |
|
| Total | 4,429 |
| | 3,795 |
| 3,471 |
| | 3,795 |
|
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $38,903 and $37,905) ($8,630 and $6,612 related to VIEs) | 28,936 |
| | 28,615 |
| |
Other Assets ($1,246 and $868 related to VIEs) | 3,006 |
| | 2,336 |
| |
Goodwill and Other Intangible Assets ($1,279 and $1,163 related to VIEs) | 5,622 |
| | 5,630 |
| |
Net Properties and Equipment (net of accumulated depreciation, depletion, and amortization of $39,998 and $37,905) ($8,785 and $6,612 related to VIEs) | | 29,091 |
| | 28,615 |
|
Other Assets ($1,273 and $868 related to VIEs) | | 2,953 |
| | 2,336 |
|
Goodwill and Other Intangible Assets ($1,271 and $1,163 related to VIEs) | | 5,614 |
| | 5,630 |
|
| Total Assets | $ | 41,993 |
| | $ | 40,376 |
| $ | 41,129 |
| | $ | 40,376 |
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| | | | | | | |
| LIABILITIES AND EQUITY | | | | | | |
| Current Liabilities | | | | | | |
| Accounts payable | | | | | | |
| Trade ($196 and $263 related to VIEs) | $ | 1,946 |
| | $ | 2,003 |
| |
| Other ($6 and $15 related to VIEs) | 165 |
| | 161 |
| |
| Trade ($155 and $263 related to VIEs) | | $ | 1,729 |
| | $ | 2,003 |
|
| Other ($9 and $15 related to VIEs) | | 167 |
| | 161 |
|
Short-term debt - Anadarko (1) | 21 |
| | 919 |
| 31 |
| | 919 |
|
| Short-term debt - WES | 2,000 |
| | 28 |
| — |
| | 28 |
|
| Current asset retirement obligations ($23 and $26 related to VIEs) | 277 |
| | 252 |
| |
| Other current liabilities ($107 and $54 related to VIEs) | 1,340 |
| | 1,295 |
| |
| Current asset retirement obligations ($25 and $26 related to VIEs) | | 303 |
| | 252 |
|
| Other current liabilities ($146 and $54 related to VIEs) | | 1,562 |
| | 1,295 |
|
| Total | 5,749 |
| | 4,658 |
| 3,792 |
| | 4,658 |
|
| Long-term Debt | | | | | | |
Long-term debt - Anadarko (1) | 10,695 |
| | 10,683 |
| 10,709 |
| | 10,683 |
|
| Long-term debt - WES | 5,208 |
| | 4,787 |
| 7,489 |
| | 4,787 |
|
| Total | 15,903 |
| | 15,470 |
| 18,198 |
| | 15,470 |
|
| Other Long-term Liabilities | | | | | | |
| Deferred income taxes | 2,624 |
| | 2,437 |
| 2,555 |
| | 2,437 |
|
| Asset retirement obligations ($312 and $260 related to VIEs) | 2,876 |
| | 2,847 |
| |
| Asset retirement obligations ($320 and $260 related to VIEs) | | 2,879 |
| | 2,847 |
|
| Other | 4,308 |
| | 4,021 |
| 4,374 |
| | 4,021 |
|
| Total | 9,808 |
| | 9,305 |
| 9,808 |
| | 9,305 |
|
| | | | | | | |
| Equity | | | | | | |
| Stockholders’ equity | | | | | | |
| Common stock, par value $0.10 per share (1.0 billion shares authorized, 577.8 million and 576.6 million shares issued) | 57 |
| | 57 |
| |
| Common stock, par value $0.10 per share (1.0 billion shares authorized, 579.1 million and 576.6 million shares issued) | | 58 |
| | 57 |
|
| Paid-in capital | 13,057 |
| | 12,393 |
| 13,135 |
| | 12,393 |
|
| Retained earnings | 1,024 |
| | 1,245 |
| |
| Treasury stock (87.5 million and 87.2 million shares) | (4,881 | ) | | (4,864 | ) | |
| Retained earnings (accumulated deficit) | | (149 | ) | | 1,245 |
|
| Treasury stock (87.7 million and 87.2 million shares) | | (4,892 | ) | | (4,864 | ) |
| Accumulated other comprehensive income (loss) | (329 | ) | | (335 | ) | (379 | ) | | (335 | ) |
| Total Stockholders’ Equity | 8,928 |
| | 8,496 |
| 7,773 |
| | 8,496 |
|
| Noncontrolling interests | 1,605 |
| | 2,447 |
| 1,558 |
| | 2,447 |
|
| Total Equity | 10,533 |
| | 10,943 |
| 9,331 |
| | 10,943 |
|
| Total Liabilities and Equity | $ | 41,993 |
| | $ | 40,376 |
| $ | 41,129 |
| | $ | 40,376 |
|
Parenthetical references reflect amounts as of March 31,June 30, 2019, and December 31, 2018.
See accompanying Notes to Consolidated Financial Statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
| | | | 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 (Accumulated Deficit) |
| Treasury Stock |
| Accumulated Other Comprehensive Income (Loss) | | Non- controlling Interests | | Total Equity |
|
| Balance at December 31, 2018 | $ | 57 |
| $ | 12,393 |
| $ | 1,245 |
| $ | (4,864 | ) | | $ | (335 | ) | | $ | 2,447 |
| $ | 10,943 |
| |
| Balance at March 31, 2019 | | $ | 57 |
| $ | 13,057 |
| $ | 1,024 |
| $ | (4,881 | ) | | $ | (329 | ) | | $ | 1,605 |
| $ | 10,533 |
|
| Net income (loss) | — |
| — |
| (15 | ) | — |
| | — |
| | 111 |
| 96 |
| — |
| — |
| (1,025 | ) | — |
| | — |
| | 80 |
| (945 | ) |
| Common stock issued | | 1 |
| 40 |
| — |
| — |
| | — |
| | — |
| 41 |
|
| Share-based compensation expense | — |
| 38 |
| — |
| — |
| | — |
| | — |
| 38 |
| — |
| 40 |
| — |
| — |
| | — |
| | — |
| 40 |
|
| Dividends—common stock | — |
| — |
| (150 | ) | — |
| | — |
| | — |
| (150 | ) | — |
| — |
| (149 | ) | — |
| | — |
| | — |
| (149 | ) |
| Repurchases of common stock | — |
| — |
| — |
| (17 | ) | | — |
| | — |
| (17 | ) | — |
| — |
| — |
| (11 | ) | | — |
| | — |
| (11 | ) |
| Subsidiary equity transactions | — |
| 626 |
| (1 | ) | — |
| | — |
| | (823 | ) | (198 | ) | — |
| (2 | ) | 1 |
| — |
| | — |
| | (1 | ) | (2 | ) |
| Distributions to noncontrolling interest owners | — |
| — |
| — |
| — |
| | — |
| | (130 | ) | (130 | ) | — |
| — |
| — |
| — |
| | — |
| | (126 | ) | (126 | ) |
| Adjustments for pension and other postretirement plans | — |
| — |
| — |
| — |
| | 5 |
| | — |
| 5 |
| — |
| — |
| — |
| — |
| | (50 | ) | | — |
| (50 | ) |
Cumulative effect of accounting change (1) | — |
| — |
| (55 | ) | — |
| | — |
| | — |
| (55 | ) | |
| Other | — |
| — |
| — |
| — |
| | 1 |
| | — |
| 1 |
| |
| Balance at March 31, 2019 | $ | 57 |
| $ | 13,057 |
| $ | 1,024 |
| $ | (4,881 | ) | | $ | (329 | ) | | $ | 1,605 |
| $ | 10,533 |
| |
| Balance at June 30, 2019 | | $ | 58 |
| $ | 13,135 |
| $ | (149 | ) | $ | (4,892 | ) | | $ | (379 | ) | | $ | 1,558 |
| $ | 9,331 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Total Stockholders’ Equity | | | |
| millions | Common Stock |
| Paid-in Capital |
| Retained Earnings (Accumulated Deficit) |
| Treasury Stock |
| Accumulated Other Comprehensive Income (Loss) | | Non- controlling Interests | | Total Equity |
|
| Balance at March 31, 2018 | $ | 57 |
| $ | 11,701 |
| $ | 1,152 |
| $ | (3,759 | ) | | $ | (410 | ) | | $ | 3,015 |
| $ | 11,756 |
|
| Net income (loss) | — |
| — |
| 29 |
| — |
| | — |
| | (12 | ) | 17 |
|
| Common stock issued | — |
| 6 |
| — |
| — |
| | — |
| | — |
| 6 |
|
| Share-based compensation expense | — |
| 45 |
| — |
| — |
| | — |
| | — |
| 45 |
|
| Dividends—common stock | — |
| — |
| (127 | ) | — |
| | — |
| | — |
| (127 | ) |
| Repurchases of common stock | — |
| 332 |
| — |
| (346 | ) | | — |
| | — |
| (14 | ) |
| Subsidiary equity transactions | — |
| (8 | ) | — |
| — |
| | — |
| | 10 |
| 2 |
|
| Settlement of tangible equity units | — |
| 230 |
| — |
| — |
| | — |
| | (300 | ) | (70 | ) |
| Distributions to noncontrolling interest owners | — |
| — |
| — |
| — |
| | — |
| | (120 | ) | (120 | ) |
| Balance at June 30, 2018 | $ | 57 |
| $ | 12,306 |
| $ | 1,054 |
| $ | (4,105 | ) | | $ | (410 | ) | | $ | 2,593 |
| $ | 11,495 |
|
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Total Stockholders’ Equity | | | |
| millions | Common Stock |
| Paid-in Capital |
| Retained Earnings (Accumulated Deficit) |
| Treasury Stock |
| Accumulated Other Comprehensive Income (Loss) | | Non- controlling Interests | | Total Equity |
|
| Balance at December 31, 2018 | $ | 57 |
| $ | 12,393 |
| $ | 1,245 |
| $ | (4,864 | ) | | $ | (335 | ) | | $ | 2,447 |
| $ | 10,943 |
|
| Net income (loss) | — |
| — |
| (1,040 | ) | — |
| | — |
| | 191 |
| (849 | ) |
| Common stock issued | 1 |
| 40 |
| — |
| — |
| | — |
| | — |
| 41 |
|
| Share-based compensation expense | — |
| 78 |
| — |
| — |
| | — |
| | — |
| 78 |
|
| Dividends—common stock | — |
| — |
| (299 | ) | — |
| | — |
| | — |
| (299 | ) |
| Repurchases of common stock | — |
| — |
| — |
| (28 | ) | | — |
| | — |
| (28 | ) |
| Subsidiary equity transactions | — |
| 624 |
| — |
| — |
| | — |
| | (824 | ) | (200 | ) |
| Distributions to noncontrolling interest owners | — |
| — |
| — |
| — |
| | — |
| | (256 | ) | (256 | ) |
| Adjustments for pension and other postretirement plans | — |
| — |
| — |
| — |
| | (45 | ) | | — |
| (45 | ) |
Cumulative effect of accounting change (1) | — |
| — |
| (55 | ) | — |
| | — |
| | — |
| (55 | ) |
| Other | — |
| — |
| — |
| — |
| | 1 |
| | — |
| 1 |
|
| Balance at June 30, 2019 | $ | 58 |
| $ | 13,135 |
| $ | (149 | ) | $ | (4,892 | ) | | $ | (379 | ) | | $ | 1,558 |
| $ | 9,331 |
|
| | | | 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 (Accumulated Deficit) |
| Treasury Stock |
| Accumulated Other Comprehensive Income (Loss) | | Non- controlling Interests | | Total Equity |
|
| Balance at December 31, 2017 | $ | 57 |
| $ | 12,000 |
| $ | 1,109 |
| $ | (2,132 | ) | | $ | (338 | ) | | $ | 3,094 |
| $ | 13,790 |
| $ | 57 |
| $ | 12,000 |
| $ | 1,109 |
| $ | (2,132 | ) | | $ | (338 | ) | | $ | 3,094 |
| $ | 13,790 |
|
| Net income (loss) | — |
| — |
| 121 |
| — |
| | — |
| | 53 |
| 174 |
| — |
| — |
| 150 |
| — |
| | — |
| | 41 |
| 191 |
|
| Common stock issued | | — |
| 6 |
| — |
| — |
| | — |
| | — |
| 6 |
|
| Share-based compensation expense | — |
| 39 |
| — |
| — |
| | — |
| | — |
| 39 |
| — |
| 84 |
| — |
| — |
| | — |
| | — |
| 84 |
|
| Dividends—common stock | — |
| — |
| (127 | ) | — |
| | — |
| | — |
| (127 | ) | — |
| — |
| (254 | ) | — |
| | — |
| | — |
| (254 | ) |
| Repurchases of common stock | — |
| (332 | ) | — |
| (1,627 | ) | | — |
| | — |
| (1,959 | ) | — |
| ��� |
| — |
| (1,973 | ) | | — |
| | — |
| (1,973 | ) |
| Subsidiary equity transactions | — |
| (6 | ) | — |
| — |
| | — |
| | 9 |
| 3 |
| — |
| (14 | ) | — |
| — |
| | — |
| | 19 |
| 5 |
|
| Settlement of tangible equity units | | — |
| 230 |
| — |
| — |
| | — |
| | (300 | ) | (70 | ) |
| Distributions to noncontrolling interest owners | — |
| — |
| — |
| — |
| | — |
| | (118 | ) | (118 | ) | — |
| — |
| — |
| — |
| | — |
| | (238 | ) | (238 | ) |
Cumulative effect of accounting change (1) | — |
| — |
| 49 |
| — |
| | (73 | ) | | (23 | ) | (47 | ) | — |
| — |
| 49 |
| — |
| | (73 | ) | | (23 | ) | (47 | ) |
| Other | — |
| — |
| — |
| — |
| | 1 |
| | — |
| 1 |
| — |
| — |
| — |
| — |
| | 1 |
| | — |
| 1 |
|
| Balance at March 31, 2018 | $ | 57 |
| $ | 11,701 |
| $ | 1,152 |
| $ | (3,759 | ) | | $ | (410 | ) | | $ | 3,015 |
| $ | 11,756 |
| |
| Balance at June 30, 2018 | | $ | 57 |
| $ | 12,306 |
| $ | 1,054 |
| $ | (4,105 | ) | | $ | (410 | ) | | $ | 2,593 |
| $ | 11,495 |
|
| |
(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 Company’s Annual Report on Form 10-K for the year ended December 31, 2018. |
See accompanying Notes to Consolidated Financial Statements.
9 | APC 2019 FORM 10-Q | 10
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | Three Months Ended | Six Months Ended |
| | March 31, | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
|
| Cash Flows from Operating Activities | | | | | | |
| Net income (loss) | $ | 96 |
| | $ | 174 |
| $ | (849 | ) | | $ | 191 |
|
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | | | | | | |
| Depreciation, depletion, and amortization | 1,081 |
| | 990 |
| 2,242 |
| | 1,993 |
|
| Deferred income taxes | 1 |
| | 42 |
| (54 | ) | | 27 |
|
| Dry hole expense and impairments of unproved properties | — |
| | 106 |
| 41 |
| | 149 |
|
| Impairments | — |
| | 19 |
| — |
| | 147 |
|
| (Gains) losses on divestitures, net | 5 |
| | 24 |
| (1 | ) | | (28 | ) |
| Total (gains) losses on derivatives, net | 315 |
| | 36 |
| 569 |
| | 473 |
|
| Operating portion of net cash received (paid) in settlement of derivative instruments | 1 |
| | (63 | ) | 2 |
| | (234 | ) |
| Other | 42 |
| | 74 |
| 112 |
| | 139 |
|
| Changes in assets and liabilities | | | | | | |
| (Increase) decrease in accounts receivable | (39 | ) | | 23 |
| 228 |
| | (91 | ) |
| Increase (decrease) in accounts payable and other current liabilities | (294 | ) | | 45 |
| (271 | ) | | 91 |
|
| Other items, net | (79 | ) | | (40 | ) | (114 | ) | | (202 | ) |
| Net cash provided by (used in) operating activities | 1,129 |
| | 1,430 |
| 1,905 |
| | 2,655 |
|
| Cash Flows from Investing Activities | | | | | | |
| Additions to properties and equipment | (1,389 | ) | | (1,547 | ) | (2,691 | ) | | (3,277 | ) |
| Divestitures of properties and equipment and other assets | 7 |
| | 371 |
| 31 |
| | 384 |
|
| Other, net | (146 | ) | | 63 |
| (125 | ) | | (163 | ) |
| Net cash provided by (used in) investing activities | (1,528 | ) | | (1,113 | ) | (2,785 | ) | | (3,056 | ) |
| Cash Flows from Financing Activities | | | | | | |
| Borrowings, net of issuance costs | 2,420 |
| | 1,333 |
| 2,700 |
| | 1,333 |
|
| Repayments of debt | (935 | ) | | (639 | ) | (940 | ) | | (764 | ) |
| Financing portion of net cash received (paid) for derivative instruments | (98 | ) | | 54 |
| (228 | ) | | 55 |
|
| Increase (decrease) in outstanding checks | 68 |
| | (26 | ) | 26 |
| | 34 |
|
| Dividends paid | (150 | ) | | (127 | ) | (299 | ) | | (254 | ) |
| Repurchases of common stock | (17 | ) | | (1,959 | ) | (28 | ) | | (1,973 | ) |
| Issuances of common stock | | 41 |
| | 6 |
|
| Distributions to noncontrolling interest owners | (130 | ) | | (118 | ) | (256 | ) | | (238 | ) |
| Payments of future hard-minerals royalty revenues conveyed | (24 | ) | | (25 | ) | (24 | ) | | (25 | ) |
| Other | (5 | ) | | — |
| (12 | ) | | — |
|
| Net cash provided by (used in) financing activities | 1,129 |
| | (1,507 | ) | 980 |
| | (1,826 | ) |
| Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents | 1 |
| | — |
| 2 |
| | (15 | ) |
| Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents | 731 |
| | (1,190 | ) | 102 |
| | (2,242 | ) |
| Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at Beginning of Period | 1,429 |
| | 4,674 |
| 1,429 |
| | 4,674 |
|
| Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at End of Period | $ | 2,160 |
| | $ | 3,484 |
| $ | 1,531 |
| | $ | 2,432 |
|
See accompanying Notes to Consolidated Financial Statements.
11 | APC 2019 FORM 10-Q | 10
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies |
GeneralAnadarko Petroleum Corporation is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and is continuing to advanceadvancing its Mozambique LNG project toward FID.to the construction phase after announcing FID on June 18, 2019. In addition, the Company engages in gathering, compressing, treating, processing, and transporting of natural gas; gathering, stabilizing, and transporting of oil and NGLs; and gathering and disposing of produced water. The Company also participates in the hard-minerals business through royalty arrangements.
Basis of PresentationThe accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. Generally Accepted Accounting Principles for interim financial information and the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain notes and other information have been condensed or omitted. The accompanying interim financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s consolidated financial statements. Certain prior-period amounts have been reclassified to conform to the current-period presentation. These interim financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.2018, as well as the Form 8-K filed on May 15, 2019 to recast the segment information included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, following a change in reportable segments during the quarter ended March 31, 2019.
Chevron Merger On April 11, 2019, the Company entered into the Chevron Merger Agreement. On April 24, 2019, Occidental announced a proposal to acquire Anadarko and further revised its proposal on May 5, 2019. On May 6, 2019, Anadarko announced that the Board had unanimously determined that the Occidental proposal was a “Superior Proposal” as defined in the Chevron Merger Agreement pursuantand, on May 9, 2019, provided Chevron a notice terminating the Chevron Merger Agreement. Pursuant to which, and subject to the conditions of the agreement, all outstanding shares of Anadarko will be acquired by Chevron in a stock and cash transaction valued at $33 billion, or $65.00 per share, as of the announcement date. Under the terms of the Chevron Merger Agreement, the Company paid the Chevron Merger Termination Fee of $1.0 billion. Also, on May 9, 2019, the Company entered into the Occidental Merger Agreement, which provides that, among other things, and subject to the terms and conditions of the Occidental Merger Agreement, a wholly owned subsidiary of Occidental will be merged with and into Anadarko, with Anadarko continuing as the surviving corporation and a wholly owned subsidiary of Occidental. Pursuant to the Occidental Merger Agreement, at the effective time of the Occidental Merger and subject to potential further adjustments as specified in the Occidental Merger Agreement, Anadarko stockholders will receive 0.3869$59.00 in cash and 0.2934 of a share of ChevronOccidental common stock and $16.25 in cash for each share of Anadarko share.common stock, plus cash in lieu of any fractional Occidental shares that otherwise would have been issued. The transaction was approved by the Boards of Directors of both companies. On May 6, 2019, Anadarko announced that the Board unanimously determined that theThe Occidental Proposal constituted a “Superior Proposal” as defined in the Chevron Merger Agreement. Under the terms of the Occidental Proposal, Occidental would acquire Anadarko for consideration consisting of $59.00 in cash and 0.2934 of a share of Occidental common stock per share of Anadarko common stock. Anadarko has notified Chevron that (i) the Board has unanimously determined that the Occidental Proposal constitutes a "Superior Proposal" and (ii) after complying with its obligations to Chevron under the Chevron Merger Agreement, Anadarko intends to terminate the Chevron Merger Agreement in order to enter into a definitive merger agreement with Occidental in connection with the Occidental Proposal. Pursuant to the Chevron Merger Agreement, Chevron has the right, during the four business day period ending on May 10, 2019, which may be extended in accordance with the terms of the Chevron Merger Agreement, to propose revisions to the terms of the Chevron Merger Agreement, or to make another proposal. If Anadarko terminates the Chevron Merger Agreement in order to enter into a definitive agreement with respect to the Occidental Proposal, Anadarko will pay Chevron a $1.0 billion termination fee as required by the Chevron Merger Agreement. The Chevron Merger Agreement remains in effect unless and until terminated, and accordingly, the Board reaffirms its existing recommendation of the transaction with Chevron at this time. Either transaction would beis subject to Anadarko stockholder approval regulatory approvals, and other customary closing conditions. Anadarko is holding a special meeting of its stockholders on August 8, 2019, for holders of record as of July 11, 2019, to vote on the proposal necessary to complete the Occidental Merger. Assuming all closing conditions are satisfied, including obtaining the requisite approval from Anadarko stockholders, Occidental and Anadarko expect the Occidental Merger to close shortly after the special meeting of Anadarko stockholders.
In addition to the Chevron Merger Termination Fee, Anadarko has incurred merger transaction costs of $42 million as of June 30, 2019.
Midstream Asset Sale and WES Merger On February 28, 2019, Anadarko completed the previously announced contribution and sale of substantially all of its midstream assets, which consisted of oil infrastructure assets in the DJ basin and oil and water infrastructure assets in the Delaware basin, to WES Operating for $4.0 billion, with $2.0 billion of cash proceeds and $2.0 billion in WES Operating common units. As a result, the Company will no longer reportreports an Other Midstream segment and will now havehas two reporting segments: Exploration and Production and WES Midstream. Prior period amounts have been reclassified to conform to the current period’scurrent-period presentation. See Note 17—19—Segment Informationfor information on the Company’s reporting segments. Immediately after the asset contribution and sale, a wholly owned subsidiary of WES merged with and into WES Operating, with WES Operating continuing as the surviving entity and a subsidiary of WES, resulting in a simplified midstream structure. Under the terms of the WES Merger, WES acquired all of the outstanding publicly held common units of WES Operating and substantially all of the WES Operating common units owned by Anadarko and its affiliates. WES Operating survived as a partnership with no publicly traded equity, owned 98% by WES and 2% by Anadarko. WES Operating owns all the operating assets and equity investments of WES, is the borrower for all existing WES debt and is expected to be the borrower for all future debt. Anadarko maintains operating control of WES, with approximately 55.5% ownership of the combined entity.
11 | APC 2019 FORM 10-Q | 12
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
| 1. Summary of Significant Accounting Policies (Continued) |
The consolidated financial statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and VIEs for which Anadarko is the primary beneficiary. The Company has determined that WES is a VIE. Anadarko is considered the primary beneficiary and consolidates WES. WES functions with a capital structure that is separate from Anadarko, consisting of its 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 noncontrolled entities that 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. Investments are included in other assets on the Company’s Consolidated Balance Sheets.
Recently Adopted Accounting Standards
ASU 2016-02, Leases (Topic 842)This ASU requires lessees to recognize a lease liability and an ROU asset on the balance sheet for all leases, including operating leases. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The Company adopted Topic 842 on January 1, 2019, using the modified retrospective method applied to all leases that existed on January 1, 2019, and prior-period financial statements were not adjusted. Anadarko elected 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 ROU assets and lease liabilities related to leases existing at January 1, 2019. The difference between ROU assets and operating lease liabilities, net of the deferred tax impact, was recognized as a $55 million reduction in the opening balance of retained earnings as a cumulative effect adjustment. See Note 9—10—Leases for additional information.
Accounting Policy
Leases Anadarko determines if an arrangement is a lease based on rights and obligations conveyed at inception of a contract. At the commencement date, a lease is classified as either operating or finance, and an ROU asset and lease liability is recognized based on the present value of future lease payments over the lease term. As the rate implicit in Anadarko’s leases generally is not readily determinable, the Company discounts lease liabilities using the Company’s incremental borrowing rate at the commencement date. Non-lease components associated with leases that begin in 2019 or later are accounted for as part of the lease component, and prepaid lease payments are included in the ROU asset. Options to extend or terminate a lease are included in the lease term when it is reasonably certain that Anadarko will exercise that option. Leases of 12 months or less are not recognized on the Company’s Consolidated Balance Sheet.Sheets.
Lease cost is recognized over the lease term, unless the end of the useful life of the underlying asset in a finance lease is before the end of the lease term. Lease cost is recognized on a straight-line basis unless another method better represents the pattern that benefit is expected to be derived from the right to use the underlying asset. For finance leases, interest expense is recognized over the lease term using the effective interest method. Variable lease payments are recognized when the obligation for those payments is incurred.
Generally, a contract in a joint arrangement is evaluated as a lease if Anadarko is the operator. Anadarko recognizes an ROU asset and lease liability for the full amount of each contract determined to be a lease, although a portion of lease payments generally is generally recovered from partners. Lease payments associated with the drilling of exploratory wells and development wells net of amounts billed to partners initially will initially be capitalized as a component of oil and gas properties and either depreciated, impaired, or written off as exploration expense in future periods.
13 | APC 2019 FORM 10-Q | 12
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
| 2. Revenue from Contracts with Customers |
Disaggregation of Revenue from Contracts with CustomersThe following table disaggregates revenue by significant product type and segment:
| | | millions | Exploration
& Production | | WES Midstream | | Other and
Intersegment
Eliminations | | Total | | Exploration
& Production | | WES Midstream | | Other and
Intersegment
Eliminations | | Total | |
| Three Months Ended March 31, 2019 | | | | | | | | | |
| Three Months Ended June 30, 2019 | | | | | | | | | |
| Oil sales | | $ | 2,096 |
| | $ | — |
| | $ | — |
| | $ | 2,096 |
| | $ | 2,470 |
| | $ | — |
| | $ | — |
| | $ | 2,470 |
|
| Natural-gas sales | | 320 |
| | — |
| | — |
| | 320 |
| | 205 |
| | — |
| | — |
| | 205 |
|
| Natural-gas liquids sales | | 240 |
| | — |
| | — |
| | 240 |
| | 216 |
| | — |
| | — |
| | 216 |
|
Gathering, processing, and marketing sales (1) | | 1 |
| | 672 |
| | (25 | ) | | 648 |
| | 1 |
| | 685 |
| | (82 | ) | | 604 |
|
| Other, net | | 9 |
| | — |
| | 25 |
| | 34 |
| | 12 |
| | — |
| | 21 |
| | 33 |
|
| Total Revenue from Customers | | $ | 2,666 |
| | $ | 672 |
| | $ | — |
| | $ | 3,338 |
| | $ | 2,904 |
| | $ | 685 |
| | $ | (61 | ) | | $ | 3,528 |
|
Gathering, processing, and marketing sales (2) | | — |
| | — |
| | (178 | ) | | (178 | ) | | — |
| | — |
| | (139 | ) | | (139 | ) |
| Gains (losses) on divestitures, net | | — |
| | — |
| | (5 | ) | | (5 | ) | | 6 |
| | — |
| | — |
| | 6 |
|
| Other, net | | (1 | ) | | 57 |
| | 7 |
| | 63 |
| | (16 | ) | | 70 |
| | (7 | ) | | 47 |
|
| Total Revenue from Other than Customers | | $ | (1 | ) | | $ | 57 |
| | $ | (176 | ) | | $ | (120 | ) | | $ | (10 | ) | | $ | 70 |
| | $ | (146 | ) | | $ | (86 | ) |
| Total Revenue and Other | | $ | 2,665 |
| | $ | 729 |
| | $ | (176 | ) | | $ | 3,218 |
| | $ | 2,894 |
| | $ | 755 |
| | $ | (207 | ) | | $ | 3,442 |
|
| | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2018 | | | | | | | | | |
| Three Months Ended June 30, 2018 | | | | | | | | | |
| Oil sales | | $ | 2,127 |
| | $ | — |
| | $ | — |
| | $ | 2,127 |
| | $ | 2,265 |
| | $ | — |
| | $ | — |
| | $ | 2,265 |
|
| Natural-gas sales | | 247 |
| | — |
| | — |
| | 247 |
| | 203 |
| | — |
| | — |
| | 203 |
|
| Natural-gas liquids sales | | 292 |
| | — |
| | — |
| | 292 |
| | 318 |
| | — |
| | — |
| | 318 |
|
Gathering, processing, and marketing sales (1) | | — |
| | 502 |
| | 46 |
| | 548 |
| | — |
| | 519 |
| | 84 |
| | 603 |
|
| Other, net | | 3 |
| | — |
| | 19 |
| | 22 |
| | 4 |
| | — |
| | 21 |
| | 25 |
|
| Total Revenue from Customers | | $ | 2,669 |
| | $ | 502 |
| | $ | 65 |
| | $ | 3,236 |
| | $ | 2,790 |
| | $ | 519 |
| | $ | 105 |
| | $ | 3,414 |
|
Gathering, processing, and marketing sales (2) | | — |
| | (1 | ) | | (187 | ) | | (188 | ) | | — |
| | (1 | ) | | (220 | ) | | (221 | ) |
| Gains (losses) on divestitures, net | | (33 | ) | | — |
| | 9 |
| | (24 | ) | | 52 |
| | 1 |
| | (1 | ) | | 52 |
|
| Other, net | | (12 | ) | | 44 |
| | (11 | ) | | 21 |
| | (1 | ) | | 39 |
| | 8 |
| | 46 |
|
| Total Revenue from Other than Customers | | $ | (45 | ) | | $ | 43 |
| | $ | (189 | ) | | $ | (191 | ) | | $ | 51 |
| | $ | 39 |
| | $ | (213 | ) | | $ | (123 | ) |
| Total Revenue and Other | | $ | 2,624 |
| | $ | 545 |
| | $ | (124 | ) | | $ | 3,045 |
| | $ | 2,841 |
| | $ | 558 |
| | $ | (108 | ) | | $ | 3,291 |
|
| |
(1) | The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $209$176 million and intersegment eliminations of $(223)$(233) million for the three months ended March 31,June 30, 2019, and sales of third-party natural gas and NGLs of $224$261 million and intersegment eliminations of $(163)$(174) million for the three months ended March 31,June 30, 2018. |
| |
(2) | The amount in Other and Intersegment Eliminations 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. |
13 | APC 2019 FORM 10-Q | 14
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
| 2. Revenue from Contracts with Customers (Continued) |
|
| | | | | | | | | | | | | | | | |
| millions | Exploration
& Production | | WES Midstream | | Other and
Intersegment
Eliminations | | Total | |
| Six Months Ended June 30, 2019 | | | | | | | | |
| Oil sales | | $ | 4,566 |
| | $ | — |
| | $ | — |
| | $ | 4,566 |
|
| Natural-gas sales | | 525 |
| | — |
| | — |
| | 525 |
|
| Natural-gas liquids sales | | 456 |
| | — |
| | — |
| | 456 |
|
Gathering, processing, and marketing sales (1) | | 2 |
| | 1,357 |
| | (107 | ) | | 1,252 |
|
| Other, net | | 21 |
| | — |
| | 46 |
| | 67 |
|
| Total Revenue from Customers | | $ | 5,570 |
| | $ | 1,357 |
| | $ | (61 | ) | | $ | 6,866 |
|
Gathering, processing, and marketing sales (2) | | — |
| | — |
| | (317 | ) | | (317 | ) |
| Gains (losses) on divestitures, net | | 6 |
| | — |
| | (5 | ) | | 1 |
|
| Other, net | | (17 | ) | | 132 |
| | (5 | ) | | 110 |
|
| Total Revenue from Other than Customers | | $ | (11 | ) | | $ | 132 |
| | $ | (327 | ) | | $ | (206 | ) |
| Total Revenue and Other | | $ | 5,559 |
| | $ | 1,489 |
| | $ | (388 | ) | | $ | 6,660 |
|
| | | | | | | | | |
| Six Months Ended June 30, 2018 | | | | | | | | |
| Oil sales | | $ | 4,392 |
| | $ | — |
| | $ | — |
| | $ | 4,392 |
|
| Natural-gas sales | | 450 |
| | — |
| | — |
| | 450 |
|
| Natural-gas liquids sales | | 610 |
| | — |
| | — |
| | 610 |
|
Gathering, processing, and marketing sales (1) | | — |
| | 1,021 |
| | 130 |
| | 1,151 |
|
| Other, net | | 7 |
| | — |
| | 40 |
| | 47 |
|
| Total Revenue from Customers | | $ | 5,459 |
| | $ | 1,021 |
| | $ | 170 |
| | $ | 6,650 |
|
Gathering, processing, and marketing sales (2) | | — |
| | (2 | ) | | (407 | ) | | (409 | ) |
| Gains (losses) on divestitures, net | | 19 |
| | 1 |
| | 8 |
| | 28 |
|
| Other, net | | (13 | ) | | 80 |
| | — |
| | 67 |
|
| Total Revenue from Other than Customers | | $ | 6 |
| | $ | 79 |
| | $ | (399 | ) | | $ | (314 | ) |
| Total Revenue and Other | | $ | 5,465 |
| | $ | 1,100 |
| | $ | (229 | ) | | $ | 6,336 |
|
| |
(1) | The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $381 million and intersegment eliminations of $(456) million for the six months ended June 30, 2019, and sales of third-party natural gas and NGLs of $485 million and intersegment eliminations of $(337) million for the six months ended June 30, 2018. |
| |
(2) | The amount in Other and Intersegment Eliminations 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, 2018 | $ | 150 |
|
Increase due to cash received, excluding revenues recognized in the period (1) | 20 |
|
Decrease due to revenue recognized (2) | (23 | ) |
| Balance at June 30, 2019 | $ | 147 |
|
| | |
| Contract liabilities at June 30, 2019 | |
| Other current liabilities | $ | 19 |
|
| Other long-term liabilities - other | 128 |
|
| Total contract liabilities from contracts with customers | $ | 147 |
|
| |
(1) | Includes $(26) million for the three months ended June 30, 2019. |
| |
(2) | Includes $7 million for the three months ended June 30, 2019. |
|
| | | |
| millions | |
| Balance at December 31, 2018 | $ | 150 |
|
| Increase due to cash received, excluding revenues recognized in the period | 21 |
|
| Decrease due to revenue recognized | (18 | ) |
| Balance at March 31, 2019 | $ | 153 |
|
| | |
| Contract liabilities at March 31, 2019 | |
| Other current liabilities | $ | 23 |
|
| Other long-term liabilities - other | 130 |
|
| Total contract liabilities from contracts with customers | $ | 153 |
|
Transaction Price Allocated to Remaining Performance ObligationsRevenue expected to be recognized from certain performance obligations that are unsatisfied as of March 31,June 30, 2019, 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 that volume.
|
| | | | | | | | | | | | | | | | |
| millions | Exploration & Production | | WES Midstream | | Other and Intersegment Eliminations | | Total | |
| Remainder of 2019 | | $ | 52 |
| | $ | 380 |
| | $ | (250 | ) | | $ | 182 |
|
| 2020 | | 103 |
| | 873 |
| | (620 | ) | | 356 |
|
| 2021 | | 103 |
| | 912 |
| | (681 | ) | | 334 |
|
| 2022 | | 7 |
| | 963 |
| | (739 | ) | | 231 |
|
| 2023 | | 7 |
| | 918 |
| | (729 | ) | | 196 |
|
| Thereafter | | 60 |
| | 4,341 |
| | (3,830 | ) | | 571 |
|
| Total | | $ | 332 |
| | $ | 8,387 |
| | $ | (6,849 | ) | | $ | 1,870 |
|
|
| | | | | | | | | | | | | | | | |
| millions | Exploration & Production | | WES Midstream | | Other and Intersegment Eliminations | | Total | |
| Remainder of 2019 | | $ | 80 |
| | $ | 533 |
| | $ | (352 | ) | | $ | 261 |
|
| 2020 | | 103 |
| | 862 |
| | (622 | ) | | 343 |
|
| 2021 | | 103 |
| | 912 |
| | (698 | ) | | 317 |
|
| 2022 | | 7 |
| | 976 |
| | (770 | ) | | 213 |
|
| 2023 | | 7 |
| | 933 |
| | (770 | ) | | 170 |
|
| Thereafter | | 58 |
| | 4,500 |
| | (4,009 | ) | | 549 |
|
| Total | | $ | 358 |
| | $ | 8,716 |
| | $ | (7,221 | ) | | $ | 1,853 |
|
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
The following summarizes the major classes of commodity inventories included in other current assets:
|
| | | | | | | | |
| millions | June 30, 2019 | | December 31, 2018 | |
| Oil | | $ | 159 |
| | $ | 139 |
|
| Natural gas | | 7 |
| | 18 |
|
| NGLs | | 58 |
| | 78 |
|
| Total commodity inventories | | $ | 224 |
| | $ | 235 |
|
The following summarizes the proceeds received and gains (losses) recognized on divestitures:
|
| | | | | | | |
| | Six Months Ended |
| | June 30, |
| millions | 2019 |
| | 2018 |
|
| Proceeds received, net of closing adjustments | $ | 31 |
| | $ | 384 |
|
| Gains (losses) on divestitures, net | 1 |
| | 28 |
|
2018 During the six months ended June 30, 2018, the Company divested of the following U.S. onshore and Gulf of Mexico assets:
| |
| – | Alaska nonoperated assets, included primarily in the Exploration and Production reporting segment, for net proceeds of $383 million and net losses of $37 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. |
|
| | | | | | | | |
| millions | March 31, 2019 | | December 31, 2018 | |
| Oil | | $ | 169 |
| | $ | 139 |
|
| Natural gas | | 1 |
| | 18 |
|
| NGLs | | 84 |
| | 78 |
|
| Total commodity inventories | | $ | 254 |
| | $ | 235 |
|
Impairments of Long-Lived Assets
2018During the three months ended June 30, 2018, the Company expensed $128 million primarily related to a gathering system in the DJ basin, included in the WES Midstream reporting segment that was permanently taken out of service in the second quarter of 2018.
Fair values were measured as of the impairment date using the income approach and Level 3 inputs. The primary assumptions used to estimate undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs.
Impairments of Unproved Properties Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. The Company recognized impairments of unproved Gulf of Mexico properties of $35 million during the six months ended June 30, 2019, and $94 million during the six months ended June 30, 2018, primarily related to blocks where the Company determined it would no longer pursue activities.
It is reasonably possible that significant 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 additional impairments.
17 | APC 2019 FORM 10-Q | 14
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
The following summarizes the proceeds received and gains (losses) recognized on divestitures:
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| millions | 2019 |
| | 2018 |
|
| Proceeds received, net of closing adjustments | $ | 7 |
| | $ | 371 |
|
| Gains (losses) on divestitures, net | (5 | ) | | (24 | ) |
2018 During the three months ended March 31, 2018, the Company divested of its Alaska nonoperated assets, included in the Exploration and Production reporting segment, for net proceeds of $383 million and net losses of $30 million in 2018 and $154 million in the fourth quarter of 2017.
|
|
5.6. Suspended Exploratory Well Costs |
The Company’s suspended exploratory well costs were $460$413 million at March 31,June 30, 2019, and $444 million at December 31, 2018. For exploratory wells, drilling costs are capitalized, or “suspended,” on the balance sheet when the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. 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. During the threesix months ended March 31,June 30, 2019, there was no exploration expense recorded for suspended exploratory well costs previously capitalized for greater than one year at December 31, 2018.
Accounts PayableAccounts payable, trade included liabilities of $248$206 million at March 31,June 30, 2019, and $180 million at December 31, 2018, 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:
|
| | | | | | | | |
| millions | June 30, 2019 | | December 31, 2018 | |
| Accrued income taxes | | $ | 135 |
| | $ | 167 |
|
| Interest payable | | 252 |
| | 267 |
|
| Production, property, and other taxes payable | | 334 |
| | 309 |
|
| Accrued employee benefits | | 229 |
| | 319 |
|
| Derivatives | | 175 |
| | 89 |
|
| Operating lease liabilities | | 249 |
| | — |
|
| Other | | 188 |
| | 144 |
|
| Total other current liabilities | | $ | 1,562 |
| | $ | 1,295 |
|
|
| | | | | | | | |
| millions | March 31, 2019 | | December 31, 2018 | |
| Accrued income taxes | | $ | 211 |
| | $ | 167 |
|
| Interest payable | | 159 |
| | 267 |
|
| Production, property, and other taxes payable | | 314 |
| | 309 |
|
| Accrued employee benefits | | 153 |
| | 319 |
|
| Derivatives | | 121 |
| | 89 |
|
| Operating lease liabilities | | 245 |
| | — |
|
| Other | | 137 |
| | 144 |
|
| Total other current liabilities | | $ | 1,340 |
| | $ | 1,295 |
|
15 | APC 2019 FORM 10-Q | 18
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
7.8. 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 Cushing, Oklahoma or Sullom Voe, Scotland for 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.
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 is subject to changes in interest 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.
Oil and Natural-Gas Production/Processing Derivative Activities The oil prices listed below are a combination of NYMEX WTI and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The Company had no natural-gas production/processing derivatives at March 31,June 30, 2019. The following is a summary of the Company’s oil derivative instruments at March 31,June 30, 2019:
|
| | | |
| | 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 |
|
|
| | | |
| | 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 volume. The purchased put establishes the minimum price that the Company will receive for the contracted volume 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.
19 | APC 2019 FORM 10-Q | 16
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
7.8. 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.
At March 31,June 30, 2019, 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 March 31,June 30, 2019:
|
| | | | | | | |
| 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 | % |
|
| | | | | | | |
| 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 Anadarko’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization, or cash 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 $41$30 million during the threesix months ended March 31,June 30, 2019, and $46$48 million during the threesix months ended March 31,June 30, 2018.
WES Interest-Rate Derivatives WES entered into interest-rate swap agreements with an aggregate notional amount of $750 million in December 2018 and $375 million in March 2019 to manage interest-rate risk associated with anticipated 2019 debt issuances. WES exchanged a floating interest rate indexed to the three-month LIBOR for a fixed interest rate. 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 March 31,June 30, 2019:
|
| | | | | | | |
| millions except percentages | | Mandatory | Weighted-Average |
|
| Notional Principal Amount | Reference Period | Termination Date | Interest Rate |
|
| $ | 375 |
| | December 2019 - 2024 | December 2019 | 2.662 | % |
| $ | 375 |
| | December 2019 - 2029 | December 2019 | 2.802 | % |
| $ | 375 |
| | December 2019 - 2049 | December 2019 | 2.885 | % |
|
| | | | | | | |
| millions except percentages | | Mandatory | Weighted-Average |
|
| Notional Principal Amount | Reference Period | Termination Date | Interest Rate |
|
| $ | 375 |
| | December 2019 - 2024 | December 2019 | 2.662 | % |
| $ | 375 |
| | December 2019 - 2029 | December 2019 | 2.802 | % |
| $ | 375 |
| | December 2019 - 2049 | December 2019 | 2.885 | % |
17 | APC 2019 FORM 10-Q | 20
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
7.8. Derivative Instruments (Continued) |
Effect of Derivative Instruments—Balance Sheet The following summarizes the fair value of the Company’s derivative instruments:
|
| | | | | | | | | | | | | | | | | |
| | Gross Derivative Assets | | Gross Derivative Liabilities |
| millions | June 30, | | December 31, | | | June 30, | | December 31, | |
| Balance Sheet Classification | | 2019 |
| | 2018 |
| | | 2019 |
| | 2018 |
|
| Commodity derivatives - Anadarko | | | | | | | | | |
| Other current assets | | $ | 37 |
| | $ | 300 |
| | | $ | (14 | ) | | $ | (126 | ) |
| Other current liabilities | | — |
| | 1 |
| | | (1 | ) | | (6 | ) |
| | | 37 |
| | 301 |
| | | (15 | ) | | (132 | ) |
Interest-rate derivatives - Anadarko (1) | |
|
| | | | | | | |
| Other current assets | | 15 |
| | 22 |
| | | — |
| | — |
|
| Other assets | | 16 |
| | 34 |
| | | — |
| | — |
|
| Other current liabilities | | — |
| | — |
| | | (86 | ) | | (82 | ) |
| Other liabilities | | — |
| | — |
| | | (1,426 | ) | | (1,156 | ) |
| | | 31 |
| | 56 |
| | | (1,512 | ) | | (1,238 | ) |
| Interest-rate derivatives - WES | | | | | | | | | |
| Other current liabilities | | — |
| | — |
| | | (103 | ) | | (8 | ) |
| Total derivatives | | $ | 68 |
| | $ | 357 |
| | | $ | (1,630 | ) | | $ | (1,378 | ) |
|
| | | | | | | | | | | | | | | | | |
| | Gross Derivative Assets | | Gross Derivative Liabilities |
| millions | March 31, | | December 31, | | | March 31, | | December 31, | |
| Balance Sheet Classification | | 2019 |
| | 2018 |
| | | 2019 |
| | 2018 |
|
| Commodity derivatives - Anadarko | | | | | | | | | |
| Other current assets | | $ | 45 |
| | $ | 300 |
| | | $ | (27 | ) | | $ | (126 | ) |
| Other current liabilities | | — |
| | 1 |
| | | (2 | ) | | (6 | ) |
| | | 45 |
| | 301 |
| | | (29 | ) | | (132 | ) |
Interest-rate derivatives - Anadarko (1) | |
|
| | | | | | | |
| Other current assets | | 21 |
| | 22 |
| | | — |
| | — |
|
| Other assets | | 30 |
| | 34 |
| | | — |
| | — |
|
| Other current liabilities | | — |
| | — |
| | | (83 | ) | | (82 | ) |
| Other liabilities | | — |
| | — |
| | | (1,237 | ) | | (1,156 | ) |
| | | 51 |
| | 56 |
| | | (1,320 | ) | | (1,238 | ) |
| Interest-rate derivatives - WES | | | | | | | | | |
| Other current liabilities | | — |
| | — |
| | | (44 | ) | | (8 | ) |
| Total derivatives | | $ | 96 |
| | $ | 357 |
| | | $ | (1,393 | ) | | $ | (1,378 | ) |
| |
(1) | Excludes amounts related to WES interest-rate swap agreements. |
Effect of Derivative Instruments—Statement of Income The following summarizes gains and losses related to derivative instruments:
|
| | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| millions | June 30, | | June 30, |
| Classification of (Gain) Loss Recognized | | 2019 |
| | 2018 |
| | | 2019 |
| | 2018 |
|
| Commodity derivatives - Anadarko | | | | | | | | | |
| Gathering, processing, and marketing sales | | $ | — |
| | $ | 1 |
| | | $ | 2 |
| | $ | 2 |
|
| (Gains) losses on derivatives, net | | (5 | ) | | 468 |
| | | 144 |
| | 630 |
|
Interest-rate derivatives - Anadarko (1) | |
| |
| | | | |
|
| (Gains) losses on derivatives, net | | 200 |
| | (32 | ) | | | 328 |
| | (159 | ) |
| Interest-rate derivatives - WES | | | | | | | | | |
| (Gains) losses on derivatives, net | | 59 |
| | — |
| | | 95 |
| | — |
|
| Total (gains) losses on derivatives, net | | $ | 254 |
| | $ | 437 |
| | | $ | 569 |
| | $ | 473 |
|
|
| | | | | | | | |
| | Three Months Ended |
| millions | March 31, |
| Classification of (Gain) Loss Recognized | | 2019 |
| | 2018 |
|
| Commodity derivatives - Anadarko | | | | |
| Gathering, processing, and marketing sales | | $ | 2 |
| | $ | 1 |
|
| (Gains) losses on derivatives, net | | 149 |
| | 162 |
|
Interest-rate derivatives - Anadarko (1) | | | |
|
| (Gains) losses on derivatives, net | | 128 |
| | (127 | ) |
| Interest-rate derivatives - WES | | | | |
| (Gains) losses on derivatives, net | | 36 |
| | — |
|
| Total (gains) losses on derivatives, net | | $ | 315 |
| | $ | 36 |
|
| |
(1) | Excludes amounts related to WES interest-rate swap agreements. |
21 | APC 2019 FORM 10-Q | 18
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
7.8. 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.
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 generally require full or partial collateralization of the Company’s obligations depending on certain credit-risk-related provisions, such as the Company’s credit rating from S&P and Moody’s. As of March 31,June 30, 2019, 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. In January 2019, Moody’s changed its outlook with respect to its rating from stable to positive. The Company may be required to post additional collateral with respect to its derivative instruments if its credit ratings decline below current levels or if the liability associated with any such derivative instrument increases above the credit threshold. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.2$1.4 billion (net of $123$264 million of collateral) at March 31,June 30, 2019, and $1.1 billion (net of $66 million of collateral) at December 31, 2018.
19 | APC 2019 FORM 10-Q | 22
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
7.8. 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 |
|
| March 31, 2019 | | | | | | | | | | | | |
| June 30, 2019 | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | | | | | | | | |
Anadarko (2) | | | | | | | | | | | | | | | | | | | | | | |
| Commodity derivatives | $ | — |
| | $ | 45 |
| | $ | — |
| | $ | (27 | ) | | $ | — |
| | $ | 18 |
| $ | — |
| | $ | 37 |
| | $ | — |
| | $ | (14 | ) | | $ | — |
| | $ | 23 |
|
| Interest-rate derivatives | — |
| | 51 |
| | — |
| | — |
| | — |
| | 51 |
| — |
| | 31 |
| | — |
| | — |
| | — |
| | 31 |
|
| Total derivative assets | $ | — |
| | $ | 96 |
| | $ | — |
| | $ | (27 | ) | | $ | — |
| | $ | 69 |
| $ | — |
| | $ | 68 |
| | $ | — |
| | $ | (14 | ) | | $ | — |
| | $ | 54 |
|
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
Anadarko (2) | | | | | | | | | | | | | | | | | | | | | | |
| Commodity derivatives | $ | — |
| | $ | (29 | ) | | $ | — |
| | $ | 27 |
| | $ | — |
| | $ | (2 | ) | $ | — |
| | $ | (15 | ) | | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | (1 | ) |
| Interest-rate derivatives | — |
| | (1,320 | ) | | — |
| | — |
| | 123 |
| | (1,197 | ) | — |
| | (1,512 | ) | | — |
| | — |
| | 264 |
| | (1,248 | ) |
| WES | | | | | | | | | | | | | | | | | | | | | | |
| Interest-rate derivatives | — |
| | (44 | ) | | — |
| | — |
| | — |
| | (44 | ) | — |
| | (103 | ) | | — |
| | — |
| | — |
| | (103 | ) |
| Total derivative liabilities | $ | — |
| | $ | (1,393 | ) | | $ | — |
| | $ | 27 |
| | $ | 123 |
| | $ | (1,243 | ) | $ | — |
| | $ | (1,630 | ) | | $ | — |
| | $ | 14 |
| | $ | 264 |
| | $ | (1,352 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | | | | | | | | |
Anadarko (2) | | | | | | | | | | | | | | | | | | | | | | |
| Commodity derivatives | $ | 1 |
| | $ | 300 |
| | $ | — |
| | $ | (127 | ) | | $ | — |
| | $ | 174 |
| $ | 1 |
| | $ | 300 |
| | $ | — |
| | $ | (127 | ) | | $ | — |
| | $ | 174 |
|
| Interest-rate derivatives | — |
| | 56 |
| | — |
| | — |
| | — |
| | 56 |
| — |
| | 56 |
| | — |
| | — |
| | — |
| | 56 |
|
| Total derivative assets | $ | 1 |
| | $ | 356 |
| | $ | — |
| | $ | (127 | ) | | $ | — |
| | $ | 230 |
| $ | 1 |
| | $ | 356 |
| | $ | — |
| | $ | (127 | ) | | $ | — |
| | $ | 230 |
|
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
Anadarko (2) | | | | | | | | | | | | | | | | | | | | | | |
| Commodity derivatives | $ | (2 | ) | | $ | (130 | ) | | $ | — |
| | $ | 127 |
| | $ | 2 |
| | $ | (3 | ) | $ | (2 | ) | | $ | (130 | ) | | $ | — |
| | $ | 127 |
| | $ | 2 |
| | $ | (3 | ) |
| Interest-rate derivatives | — |
| | (1,238 | ) | | — |
| | — |
| | 66 |
| | (1,172 | ) | — |
| | (1,238 | ) | | — |
| | — |
| | 66 |
| | (1,172 | ) |
| WES | | | | | | | | | | | | | | | | | | | | | | |
| Interest-rate derivatives | — |
| | (8 | ) | | — |
| | — |
| | — |
| | (8 | ) | — |
| | (8 | ) | | — |
| | — |
| | — |
| | (8 | ) |
| Total derivative liabilities | $ | (2 | ) | | $ | (1,376 | ) | | $ | — |
| | $ | 127 |
| | $ | 68 |
| | $ | (1,183 | ) | $ | (2 | ) | | $ | (1,376 | ) | | $ | — |
| | $ | 127 |
| | $ | 68 |
| | $ | (1,183 | ) |
| |
(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. |
23 | APC 2019 FORM 10-Q | 20
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
Debt Activity The following summarizes the Company’s borrowing activity, after eliminating the effect of intercompany transactions, during the threesix months ended March 31,June 30, 2019:
| | | | | Carrying Value | | | Carrying Value | |
| millions | Anadarko (1) | | WES | | Anadarko Consolidated | | Description | Anadarko (1) | | WES | | Anadarko Consolidated | | Description |
| Balance at December 31, 2018 | | $ | 11,354 |
| | $ | 4,815 |
| | $ | 16,169 |
| | | $ | 11,354 |
| | $ | 4,815 |
| | $ | 16,169 |
| |
| Borrowings | | | | | | | | | | | | | | |
| | | — |
| | 2,000 |
| | 2,000 |
| WES 364-Day Facility | | — |
| | 2,000 |
| | 2,000 |
| WES Term Loan Facility |
| | | — |
| | 420 |
| | 420 |
| WES RCF | | — |
| | 700 |
| | 700 |
| WES RCF |
| Repayments | | | | | | | | | | | | | | |
| | | (600 | ) | | — |
| | (600 | ) | 8.700 % Senior Notes due 2019 | | (600 | ) | | — |
| | (600 | ) | 8.700 % Senior Notes due 2019 |
| | | (300 | ) | | — |
| | (300 | ) | 6.950 % Senior Notes due 2019 | | (300 | ) | | — |
| | (300 | ) | 6.950 % Senior Notes due 2019 |
| | | — |
| | (28 | ) | | (28 | ) | WGP RCF | | — |
| | (28 | ) | | (28 | ) | WGP RCF |
| Other, net | | 12 |
| | 1 |
| | 13 |
| Amortization of discounts, premiums, and debt issuance costs | | 25 |
| | 2 |
| | 27 |
| Amortization of discounts, premiums, and debt issuance costs |
| Balance at March 31, 2019 | | $ | 10,466 |
| | $ | 7,208 |
| | $ | 17,674 |
| | |
| Balance at June 30, 2019 | | | $ | 10,479 |
| | $ | 7,489 |
| | $ | 17,968 |
| |
Debt The following summarizes the Company’s outstanding debt, including finance lease liabilities, after eliminating the effect of intercompany transactions:
|
| | | | | | | | | | | | |
| millions | Anadarko (1) | | WES | | Anadarko Consolidated | |
| June 30, 2019 | | | | | | |
| Total borrowings at face value | | $ | 11,893 |
| | $ | 7,540 |
| | $ | 19,433 |
|
Net unamortized discounts, premiums, and debt issuance costs (2) | | (1,414 | ) | | (51 | ) | | (1,465 | ) |
Total borrowings (3) | | 10,479 |
| | 7,489 |
| | 17,968 |
|
| Finance lease liabilities | | 261 |
| | — |
| | 261 |
|
| Less short-term debt | | 31 |
| | — |
| | 31 |
|
| Total long-term debt | | $ | 10,709 |
| | $ | 7,489 |
| | $ | 18,198 |
|
| | | | | | | |
| December 31, 2018 | | | | | | |
| Total borrowings at face value | | $ | 12,793 |
| | $ | 4,868 |
| | $ | 17,661 |
|
Net unamortized discounts, premiums, and debt issuance costs (2) | | (1,439 | ) | | (53 | ) | | (1,492 | ) |
Total borrowings (3) | | 11,354 |
| | 4,815 |
| | 16,169 |
|
| Finance lease liabilities | | 248 |
| | — |
| | 248 |
|
| Less short-term debt | | 919 |
| | 28 |
| | 947 |
|
| Total long-term debt | | $ | 10,683 |
| | $ | 4,787 |
| | $ | 15,470 |
|
|
| | | | | | | | | | | | |
| millions | Anadarko (1) | | WES | | Anadarko Consolidated | |
| March 31, 2019 | | | | | | |
| Total borrowings at face value | | $ | 11,893 |
| | $ | 7,260 |
| | $ | 19,153 |
|
Net unamortized discounts, premiums, and debt issuance costs (2) | | (1,427 | ) | | (52 | ) | | (1,479 | ) |
Total borrowings (3) | | 10,466 |
| | 7,208 |
| | 17,674 |
|
| Finance lease liabilities | | 250 |
| | — |
| | 250 |
|
| Less short-term debt | | 21 |
| | 2,000 |
| | 2,021 |
|
| Total long-term debt | | $ | 10,695 |
| | $ | 5,208 |
| | $ | 15,903 |
|
| | | | | | | |
| December 31, 2018 | | | | | | |
| Total borrowings at face value | | $ | 12,793 |
| | $ | 4,868 |
| | $ | 17,661 |
|
Net unamortized discounts, premiums, and debt issuance costs (2) | | (1,439 | ) | | (53 | ) | | (1,492 | ) |
Total borrowings (3) | | 11,354 |
| | 4,815 |
| | 16,169 |
|
| Finance lease liabilities | | 248 |
| | — |
| | 248 |
|
| Less short-term debt | | 919 |
| | 28 |
| | 947 |
|
| Total long-term debt | | $ | 10,683 |
| | $ | 4,787 |
| | $ | 15,470 |
|
| |
(2) | 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. |
| |
(3) | The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured. |
21 | APC 2019 FORM 10-Q | 24
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
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 $19.3$20.2 billion at March 31,June 30, 2019, and $16.8 billion at December 31, 2018.
Anadarko Debt (Excluding WES)In January 2019, the $2.0 billion 364-day senior unsecured RCF (364-Day Facility) expired. At March 31,June 30, 2019, the Company had a $3.0 billion senior unsecured RCF maturing in January 2023 (APC RCF). At March 31,June 30, 2019, Anadarko had no outstanding borrowings under the APC RCF and was in compliance with all covenants.
In March 2019, Anadarko repaid $600 million of 8.700% Senior Notes at maturity and redeemed its $300 million of 6.950% Senior Notes due June 2019.
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. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31,June 30, 2019, as the Company has the ability and intent to refinance these obligations using long-term debt, should a put be exercised.
The Company also has 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. See Note 9—Equity-Method Investments in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.
WES and WGP Debt Effective on February 15, 2019, WES amended the maturity date of its senior unsecured RCF from February 2023 to February 2024, and upon completion of the WES Merger, expanded the borrowing capacity from $1.5 billion to $2.0 billion (WES RCF). During the threesix months ended March 31,June 30, 2019, WES borrowed $420$700 million under its RCF, which was used for general partnership purposes.purposes, including to fund capital expenditures. At March 31,June 30, 2019, WES had outstanding borrowings under its RCF of $640$920 million at an interest rate of 3.79%3.71%, outstanding letters of credit of $5 million, available borrowing capacity of $1.4$1.1 billion, and was in compliance with all covenants.
In February 2019, WES borrowed $2.0 billion under its 364-day senior unsecured credit facility (WES 364-DayTerm Loan Facility) 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. TheAs of June 30, 2019, the WES 364-DayTerm Loan Facility willwas anticipated to mature on February 27, 2020, the day prior to the one-year anniversary of the completion of the WES Merger. NetAs of June 30, 2019, net cash proceeds received from future asset sales and debt or equity offerings by WES mustwere required to be used to repay amounts outstanding under the WES 364-DayTerm Loan Facility. At March 31,June 30, 2019, WES had outstanding borrowings under its WES 364-DayTerm Loan Facility of $2.0 billion at an interest rate of 3.87%3.78% and was in compliance with all covenants.
On July 1, 2019, WES intendsentered into an amendment to refinance the obligationsWES Term Loan Facility to, among other things, (i) increase the commitments available under the 364-DayWES Term Loan Facility priorfrom $2.0 billion to its$3.0 billion, the incremental $1.0 billion of which may be drawn by WES on or before September 30, 2019, (ii) extend the maturity indate from February 2020.27, 2020 to December 31, 2020, and (iii) modify the provision requiring that all debt issuance proceeds be used to repay the WES Term Loan Facility to allow for a $1.0 billion carve out of debt offering proceeds.
In March 2019, the $35 million senior secured RCF (WGP RCF) matured following the completion of the WES Merger. During the threesix months ended March 31,June 30, 2019, WES made repayments of $28 million for the WGP RCF.
25 | APC 2019 FORM 10-Q | 22
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
Operating LeasesAt March 31,June 30, 2019, total lease liabilities related to operating leases were $551$557 million and primarily related to offshore and onshore drilling rigs and real estate.
The operating lease liabilities included $216$177 million for three offshore drilling vessels and certain contracts for onshore drilling rigs expiring at various dates through 2021. Lease payments commonly vary based on activities being performed by the rig. To the extent that lease payments vary from amounts recognized on the Company’s balance sheet, the amount is included in variable lease cost.
Additionally, the Company has $193$187 million of operating lease liabilities for real estate, primarily related to the Company’s Denver corporate office lease expiring in 2033, with options to terminate the lease early.
Finance LeasesAt March 31,June 30, 2019, total lease liabilities related to finance leases were $250$261 million and primarily related to an FPSO for the Company’s TEN field in Ghana. The initial FPSO lease term ends in 20262027 with annual renewal periods for an additional 10 years, annual purchase options that decrease over time, and no residual value guarantees.
The following table summarizes information related to the Company’s leases at March 31,June 30, 2019:
|
| | | | | | | | |
| millions except lease term and discount rate | Operating Leases | | Finance Leases | |
| Assets | | | | |
| Other assets | | $ | 539 |
| | $ | — |
|
| Net properties and equipment | | — |
| | 193 |
|
Total lease assets (1) | | $ | 539 |
| | $ | 193 |
|
| | | | | |
| Liabilities | | | | |
| Current liabilities | | | | |
| Other current liabilities | | $ | 249 |
| | $ | — |
|
| Short-term debt - Anadarko | | — |
| | 31 |
|
| Long-term liabilities | | | | |
| Other | | 308 |
| | — |
|
| Long-term debt - Anadarko | | — |
| | 230 |
|
Total lease liabilities (1) | | $ | 557 |
| | $ | 261 |
|
| | | | | |
| Weighted-average remaining lease term (years) | | 5 |
| | 16 |
|
Weighted-average discount rate (2) | | 4.3 | % | | 15.1 | % |
|
| | | | | | | | |
| millions except lease term and discount rate | Operating Leases | | Finance Leases | |
| Assets | | | | |
| Other assets | | $ | 534 |
| | $ | — |
|
| Net properties and equipment | | — |
| | 186 |
|
Total lease assets (1) | | $ | 534 |
| | $ | 186 |
|
| | | | | |
| Liabilities | | | | |
| Current liabilities | | | | |
| Other current liabilities | | $ | 245 |
| | $ | — |
|
| Short-term debt - Anadarko | | — |
| | 21 |
|
| Long-term liabilities | | | | |
| Other | | 306 |
| | — |
|
| Long-term debt - Anadarko | | — |
| | 229 |
|
Total lease liabilities (1) | | $ | 551 |
| | $ | 250 |
|
| | | | | |
| Weighted-average remaining lease term (years) | | 5 |
| | 16 |
|
Weighted-average discount rate (2) | | 4.3 | % | | 15.4 | % |
| |
(1) | Includes additions to ROU assets and lease liabilities of $60$126 million related to operating leases and $6$22 million related to finance leases for the threesix months ended March 31,June 30, 2019. |
| |
(2) | The FPSO finance lease commenced prior to the adoption of ASU 2016-02, Leases (Topic 842). In accordance with previous accounting guidance, the implied rate is based on the fair value of the underlying asset. |
23 | APC 2019 FORM 10-Q | 26
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
The following table summarizes the Company’s lease cost before amounts recovered from partners:
| | | | Three Months Ended | | Three Months Ended | | | Six Months Ended | |
| millions | March 31, 2019 | | June 30, 2019 | | | June 30, 2019 | |
| Operating lease cost | | $ | 78 |
| | $ | 70 |
| | $ | 148 |
|
| Short-term lease cost | | 19 |
| | 42 |
| | 61 |
|
| Variable lease cost | | 39 |
| | 37 |
| | 76 |
|
| Finance lease cost | | | | | | |
| Amortization of ROU assets | | 10 |
| | 10 |
| | 20 |
|
| Interest on lease liabilities | | 9 |
| | 9 |
| | 18 |
|
| Total lease cost | | $ | 155 |
| | $ | 168 |
| | $ | 323 |
|
The following table summarizes cash paid for amounts included in the measurement of lease liabilities:
|
| | | | | | | | |
| | Six Months Ended |
| | June 30, 2019 |
| millions | Operating Leases | | Finance Leases | |
| Operating cash flows | | $ | 133 |
| | $ | 18 |
|
| Investing cash flows | | 37 |
| | — |
|
| Financing cash flows | | — |
| | 9 |
|
|
| | | | | | | | |
| | Three Months Ended |
| | March 31, 2019 |
| millions | Operating Leases | | Finance Leases | |
| Operating cash flows | | $ | 78 |
| | $ | 9 |
|
| Investing cash flows | | 24 |
| | — |
|
| Financing cash flows | | — |
| | 4 |
|
The following table reconciles the undiscounted cash flows to the operating and finance lease liabilities recorded on the Company’s Consolidated Balance Sheet at March 31,June 30, 2019:
| | | millions | Operating Leases (1) | | Finance Leases | | Operating Leases (1) | | Finance Leases | |
| Remainder of 2019 | | $ | 185 |
| | $ | 46 |
| | $ | 134 |
| | $ | 35 |
|
| 2020 | | 166 |
| | 51 |
| | 191 |
| | 62 |
|
| 2021 | | 60 |
| | 50 |
| | 70 |
| | 52 |
|
| 2022 | | 43 |
| | 46 |
| | 49 |
| | 48 |
|
| 2023 | | 30 |
| | 43 |
| | 35 |
| | 44 |
|
| Thereafter | | 142 |
| | 324 |
| | 155 |
| | 322 |
|
| Total lease payments | | $ | 626 |
| | $ | 560 |
| | $ | 634 |
| | $ | 563 |
|
| Less portion representing imputed interest | | 75 |
| | 310 |
| | 77 |
| | 302 |
|
| Total lease liabilities | | $ | 551 |
| | $ | 250 |
| | $ | 557 |
| | $ | 261 |
|
| |
(1) | For leases commencing prior to 2019, lease payments exclude payments to lessors for drilling rig services and real estate services, taxes, and common area maintenance. |
27 | APC 2019 FORM 10-Q | 24
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
The following table summarizes future minimum lease payments related to the Company’s operating and finance leases as of December 31, 2018:
|
| | | | | | | | |
| millions | Operating Leases | | Finance Leases | |
| 2019 | | $ | 264 |
| | $ | 58 |
|
| 2020 | | 139 |
| | 50 |
|
| 2021 | | 57 |
| | 48 |
|
| 2022 | | 35 |
| | 45 |
|
| 2023 | | 24 |
| | 43 |
|
| Thereafter | | 135 |
| | 323 |
|
| Total lease payments | | $ | 654 |
| | $ | 567 |
|
| Less portion representing imputed interest | | * |
| | 319 |
|
| Total lease liabilities | | * |
| | $ | 248 |
|
| |
| * | Prior to the adoption of ASU 2016-02, Leases (Topic 842) on January 1, 2019, operating lease liabilities were not recognized on the Company’s Consolidated Balance Sheet.Sheets. Refer to Note 1—Summary of Significant Accounting Policies for additional information. |
25 | APC 2019 FORM 10-Q | 28
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
The following summarizes income tax expense (benefit) and effective tax rates:
|
| | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
| millions except percentages | | 2019 |
| | 2018 |
| | | 2019 |
| | 2018 |
|
| Current income tax expense (benefit) | | $ | 269 |
| | $ | 147 |
| | | $ | 437 |
| | $ | 237 |
|
| Deferred income tax expense (benefit) | | (60 | ) | | (22 | ) | | | (62 | ) | | 14 |
|
| Total income tax expense (benefit) | | $ | 209 |
| | $ | 125 |
| | | $ | 375 |
| | $ | 251 |
|
| Income (loss) before income taxes | | (736 | ) | | 142 |
| | | (474 | ) | | 442 |
|
| Effective tax rate | | (28 | )% | | 88 | % | | | (79 | )% | | 57 | % |
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| millions except percentages | 2019 |
| | 2018 |
|
| Current income tax expense (benefit) | $ | 168 |
| | $ | 90 |
|
| Deferred income tax expense (benefit) | (2 | ) | | 36 |
|
| Total income tax expense (benefit) | $ | 166 |
| | $ | 126 |
|
| Income (loss) before income taxes | 262 |
| | 300 |
|
| Effective tax rate | 63 | % | | 42 | % |
The Company’s tax provision for interim periods is determined using an estimate of its annual current and deferred effective tax rates, adjusted for discrete items. Each quarter, the Company updates these rates and records a cumulative adjustment to current and deferred tax expense by applying the rates to the year-to-date pre-tax income excluding discrete items. The Company’s quarterly estimate of its annual current and deferred effective tax rates can vary significantly based on various forecasted items, including future commodity prices, capital expenditures, expenses for which tax benefits are not recognized, and the geographic mix of pre-tax income and losses.
The variance from the U.S. federal statutory rate of 21% for the three and six months ended March 31,June 30, 2019, was primarily attributable to the following items:
| |
| – | tax impact from foreign operations |
| |
| – | non-deductible Algerian exceptional profits tax for Algerian income tax purposes |
| |
| – | income attributable to noncontrolling interests |
| |
| – | non-deductible Chevron Merger Termination Fee |
The variance from the U.S. federal statutory rate of 21% for the three and six months ended March 31,June 30, 2018, was primarily attributable to the following items:
| |
– | state taxes, net of federal benefits |
| |
| – | tax impact from foreign operations |
| |
| – | non-deductible Algerian exceptional profits tax for Algerian income tax purposes |
| |
– | net changes in uncertain tax positions |
| |
– | income attributable to noncontrolling interests. |
The Company recognized a tax benefit of $346 million as of March 31,June 30, 2019 and December 31, 2018, related to the deduction of its 2015 settlement payment for the Tronox Adversary Proceeding. This benefit is net of uncertain tax positions of $1.2 billion as of March 31,June 30, 2019 and December 31, 2018, due to uncertainty related to the deductibility of the settlement payment. Due to the deduction of the settlement payment on the Company’s 2015 tax return, the Company had a net operating loss carryback, 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 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 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 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 the amount of uncertain tax position and/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 currently anticipate a decision to be entered before 2022.
29 | APC 2019 FORM 10-Q | 26
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
Anadarko 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 various processing, transportation, storage, and purchase agreements to access markets and provide flexibility to sell its oil, natural gas, and NGLs in certain areas.
On June 18, 2019, the Company and the co-venturers in Mozambique’s Offshore Area 1 announced FID on the Anadarko-led Area 1 Mozambique LNG project. This official declaration of FID confirms the Golfinho Atum Plan of Development is now effective with notice provided to the Government of Mozambique that all conditions precedent have been satisfied, and the project can now advance to the construction phase. Subsequent to FID, Anadarko began entering into various long-term contractual commitments pertaining primarily to offshore engineering, procurement, construction, and installation activities in Mozambique. These commitments as of June 30, 2019, have been included in the table below.
The Company’s various long-term contractual obligations expire at various dates through 2034. The following summarizes the gross aggregate future payments under these contracts at June 30, 2019:
|
| | | |
| millions | |
| 2019 | $ | 1,028 |
|
| 2020 | 1,627 |
|
| 2021 | 1,419 |
|
| 2022 | 1,306 |
|
| 2023 | 714 |
|
| Thereafter | 1,467 |
|
Total (1)(2) | $ | 7,561 |
|
| |
(1) | Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator. |
| |
(2) | Includes gross commitments related to the Mozambique development activities of $2.0 billion ($507 million net to Anadarko). |
On July 26, 2019, Anadarko issued a Notice-to-Proceed to the onshore engineering, procurement, and construction contractor for the Mozambique LNG project, resulting in additional obligations with gross aggregate future payments of approximately $8.0 billion, of which $2.1 billion is net to Anadarko.
LitigationThere are no material developments in previously reported contingencies nor are there any other material matters that have arisen since the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
12.14. Pension Plans and Other Postretirement Benefits |
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 noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost:
|
| | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Benefits |
| millions |
| 2019 |
|
| 2018 |
| | | 2019 |
| | 2018 |
|
| Three Months Ended June 30 | | | | | | | | | |
| Service cost | | $ | 22 |
| | $ | 22 |
| | | $ | — |
| | $ | 1 |
|
| Interest cost | | 20 |
| | 19 |
| | | 3 |
| | 2 |
|
| Expected (return) loss on plan assets | | (20 | ) | | (20 | ) | | | — |
| | — |
|
| Amortization of net actuarial loss (gain) | | 3 |
| | 6 |
| | | — |
| | — |
|
| Amortization of net prior service cost (credit) | | — |
| | — |
| | | — |
| | (6 | ) |
| Settlement expense | | 13 |
| | — |
| | | — |
| | — |
|
| Termination benefits expense | | 2 |
| | — |
| | | — |
| | — |
|
Net periodic benefit cost (1) | | $ | 40 |
| | $ | 27 |
| | | $ | 3 |
| | $ | (3 | ) |
| | | | | | | | | | |
| Six Months Ended June 30 | | | | | | | | | |
| Service cost | | $ | 44 |
| | $ | 45 |
| | | $ | — |
| | $ | 1 |
|
| Interest cost | | 40 |
| | 38 |
| | | 6 |
| | 5 |
|
| Expected (return) loss on plan assets | | (41 | ) | | (41 | ) | | | — |
| | — |
|
| Amortization of net actuarial loss (gain) | | 7 |
| | 13 |
| | | — |
| | — |
|
| Amortization of net prior service cost (credit) | | — |
| | — |
| | | (1 | ) | | (12 | ) |
| Settlement expense | | 17 |
| | — |
| | | — |
| | — |
|
| Termination benefits expense | | 2 |
| | — |
| | | — |
| | — |
|
Net periodic benefit cost (1) | | $ | 69 |
| | $ | 55 |
| | | $ | 5 |
| | $ | (6 | ) |
|
| | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Benefits |
| millions |
| 2019 |
|
| 2018 |
| | | 2019 |
| | 2018 |
|
| Three Months Ended March 31 | | | | | | | | | |
| Service cost | | $ | 22 |
| | $ | 23 |
| | | $ | — |
| | $ | — |
|
| Interest cost | | 20 |
| | 19 |
| | | 3 |
| | 3 |
|
| Expected (return) loss on plan assets | | (21 | ) | | (21 | ) | | | — |
| | — |
|
| Amortization of net actuarial loss (gain) | | 4 |
| | 7 |
| | | — |
| | — |
|
| Amortization of net prior service cost (credit) | | — |
| | — |
| | | (1 | ) | | (6 | ) |
| Settlement expense | | 4 |
| | — |
| | | — |
| | — |
|
Net periodic benefit cost (1) | | $ | 29 |
| | $ | 28 |
| | | $ | 2 |
| | $ | (3 | ) |
| |
(1) | The service cost component of net periodic benefit cost is included in G&A; oil and gas operating expense; gathering, processing, and marketing expense; and exploration expense, and all other components of net periodic benefit cost are included in other (income) expense on the Company’s Consolidated Statements of Income. |
The Company contributed $65$91 million to funded pension plans and $21$25 million to unfunded pension plans during the threesix months ended March 31, 2019. The Company expects to contribute an additional $26 million to funded pension plans and $26 million to unfunded pension plans duringJune 30, 2019.
27 31 | APC 2019 FORM 10-Q
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
13.15. Stockholders’ Equity |
Earnings Per ShareThe Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities and TEUs as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and TEUs, if the inclusion of these items is dilutive. All outstanding TEUs were settled in June 2018.
The following provides a reconciliation between basic and diluted EPS attributable to common stockholders:
|
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended |
| | | June 30, | | | June 30, |
| millions except per-share amounts | | 2019 |
| | 2018 |
| | | 2019 |
| | 2018 |
|
| Net income (loss) | | | | | | | | | |
| Net income (loss) attributable to common stockholders | | $ | (1,025 | ) | | $ | 29 |
| | | $ | (1,040 | ) | | $ | 150 |
|
| Income (loss) effect of TEUs | | — |
| | (1 | ) | | | — |
| | (4 | ) |
| Less distributions on participating securities | | 1 |
| | 1 |
| | | 3 |
| | 2 |
|
| Basic | | $ | (1,026 | ) | | $ | 27 |
| | | $ | (1,043 | ) | | $ | 144 |
|
| Income (loss) effect of TEUs | | — |
| | — |
| | | — |
| | (1 | ) |
| Diluted | | $ | (1,026 | ) | | $ | 27 |
| | | $ | (1,043 | ) | | $ | 143 |
|
| Shares | | | | | | | | | |
| Average number of common shares outstanding—basic | | 491 |
| | 504 |
| | | 491 |
| | 511 |
|
| Dilutive effect of stock options | | — |
| | 1 |
| | | — |
| | 1 |
|
| Average number of common shares outstanding—diluted | | 491 |
| | 505 |
| | | 491 |
| | 512 |
|
| Excluded due to anti-dilutive effect | | 12 |
| | 9 |
| | | 12 |
| | 9 |
|
| Net income (loss) per common share | | | | | | | | | |
| Basic | | $ | (2.09 | ) | | $ | 0.05 |
| | | $ | (2.13 | ) | | $ | 0.28 |
|
| Diluted | | $ | (2.09 | ) | | $ | 0.05 |
| | | $ | (2.13 | ) | | $ | 0.28 |
|
| Dividends per common share | | $ | 0.30 |
| | $ | 0.25 |
| | | $ | 0.60 |
| | $ | 0.50 |
|
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| millions except per-share amounts | 2019 |
| | 2018 |
|
| Net income (loss) | | | |
| Net income (loss) attributable to common stockholders | $ | (15 | ) | | $ | 121 |
|
| Income (loss) effect of TEUs | — |
| | (3 | ) |
| Less distributions on participating securities | 2 |
| | 1 |
|
| Basic | $ | (17 | ) | | $ | 117 |
|
| Income (loss) effect of TEUs | — |
| | (1 | ) |
| Diluted | $ | (17 | ) | | $ | 116 |
|
| Shares | | | |
| Average number of common shares outstanding—basic | 490 |
| | 518 |
|
| Dilutive effect of stock options | — |
| | 1 |
|
| Average number of common shares outstanding—diluted | 490 |
| | 519 |
|
| Excluded due to anti-dilutive effect | 12 |
| | 10 |
|
| Net income (loss) per common share | | | |
| Basic | $ | (0.03 | ) | | $ | 0.23 |
|
| Diluted | $ | (0.03 | ) | | $ | 0.22 |
|
| Dividends per common share | $ | 0.30 |
| | $ | 0.25 |
|
Common StockThe Share-Repurchase Program authorizes the repurchase of the Company’s common stock in the open market or through private transactions. During 2018, the Share-Repurchase Program was expanded to $5.0 billionand extended through mid-year 2020. As of December 31, 2018, the Company had completed $3.75 billion of the Share-Repurchase Program through ASR Agreements and open-market repurchases. These transactions were accounted for as equity transactions, with all of the repurchased shares classified as treasury stock. Additionally, the receipt of these shares reduced the average number of shares of common stock outstanding used to compute both basic and diluted EPS. There were no additional repurchases of common stock under the Share-Repurchase Program for the threesix months ended March 31,June 30, 2019. No additional share repurchases under the Share-Repurchase Program are anticipated pursuant to the terms of the ChevronOccidental Merger Agreement. See Note 1—Summary of Significant Accounting Policies for additional information on the ChevronOccidental Merger Agreement.
DividendsDividends declared are recorded as a reduction of retained earnings, to the extent that retained earnings were available at the beginning of the reporting period, with any excess recorded as a reduction of paid-in capital.
APC 2019 FORM 10-Q | 28 32
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
14.16. Noncontrolling Interests |
WES is a limited partnership formed by Anadarko in September 2012 and owns a 98% limited partner interest in WES Operating, a Delaware limited partnership formed by Anadarko in 2007 to acquire, own, develop and operate midstream assets, and all of the outstanding equity interests of WES Operating’s general partner, which holds the entire non-economic general partner interest in WES Operating.
WES Operating Class C units issued to Anadarko converted into WES Operating common units in a unit-for-unit, tax-free exchange immediately prior to the closing of the WES Merger on February 28, 2019. Prior to the closing of the WES Merger, the Class C units received quarterly distributions in the form of additional Class C units. WES distributed 309 thousand Class C units to Anadarko during the threesix months ended March 31,June 30, 2019, and 1.1 million Class C units to Anadarko during 2018. See Note 1—Summary of Significant Accounting Policies for additional information on the WES Merger. At March 31,June 30, 2019, Anadarko’s ownership interest in WES consisted of a 55.5% limited partner interest and the entire non-economic general partner interest. The remaining 44.5% limited partner interest in WES was owned by the public.
At March 31,June 30, 2019, Anadarko’s ownership interest in WES Operating consisted of a 2% limited partner interest.
29 33 | APC 2019 FORM 10-Q
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
15.17. Variable Interest Entities |
Consolidated VIEs The Company determined that the partners in WES with equity at risk lack the power, through voting rights or similar rights, to direct the activities that most significantly impact WES’s economic performance; therefore, WES is considered a VIE. Anadarko, through its ownership of the general partner interest in WES, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to WES; therefore, Anadarko is considered the primary beneficiary and consolidates WES and all of its consolidated subsidiaries. For additional information on WES, see Note 14—16—Noncontrolling Interests.
Assets and Liabilities of VIEsThe assets of WES and its subsidiaries cannot be used by Anadarko for general corporate purposes and are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to WES and its subsidiaries for which the creditors do not have recourse to other Anadarko assets are included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.
All outstanding debt for WES at March 31,June 30, 2019, and December 31, 2018, including any borrowings under the WES RCF and WES 364-DayTerm Loan Facility, is recourse to WES Operating’s general partner, which in turn has been indemnified in certain circumstances by certain wholly owned subsidiaries of the Company for such liabilities. See Note 8—9—Debt for additional information on WES short-term and long-term debt balances.
VIE Financing WES’s sources of liquidity include cash and cash equivalents, cash flows generated from operations, interest income from a note receivable from Anadarko as discussed below, borrowings under the WES RCF, the issuance of additional partnership units, and debt offerings. See Note 8—9—DebtandNote 14—16—Noncontrolling Interestsfor additional information on WES financing activity.
VIE Distributions The following table presents WES distributions:
| | | | Three Months Ended | Six Months Ended |
| | March 31, | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
|
WES distributions to Anadarko (1) | $ | 105 |
| | $ | 100 |
| $ | 264 |
| | $ | 203 |
|
| WES distributions to third parties | 130 |
| | 118 |
| 255 |
| | 238 |
|
| |
(1) | WES distributions to Anadarko are eliminated upon consolidation. |
Financial Support Provided to VIEs Concurrent with the closing of its May 2008 IPO, WES Operating loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES Operating was $4$8 million for the threesix months ended March 31,June 30, 2019 and 2018. The note receivable and related interest income are eliminated in consolidation.
To reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of its contracts, Anadarko had commodity price swap agreements in place with WES Operating that expired without renewal on December 31, 2018, andwith final settlement occurred in the first quarter of 2019. WES recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price, minus (ii) the amount by which the swap price for product purchases exceeds the market price. WES recorded a capital contribution from Anadarko of $7 million for the threesix months ended March 31,June 30, 2019, and $14$28 million for the threesix months ended March 31,June 30, 2018.
APC 2019 FORM 10-Q | 30 34
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
16.18. Supplemental Cash Flow Information |
Additions 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.
The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities:
|
| | | | | | | |
| | Six Months Ended |
| | June 30, |
| millions | 2019 |
| | 2018 |
|
| Cash paid (received) | | | |
| Interest, net of amounts capitalized | $ | 536 |
| | $ | 471 |
|
| Income taxes, net of refunds | 29 |
| | 53 |
|
| Non-cash investing activities | | | |
| Fair value of properties and equipment acquired | $ | 1 |
| | $ | 7 |
|
| Asset retirement cost additions | 117 |
| | 162 |
|
| Accruals of property, plant, and equipment | 748 |
| | 1,036 |
|
| Net liabilities assumed (divested) in acquisitions and divestitures | — |
| | (97 | ) |
| Non-cash investing and financing activities | | | |
| Finance leases | $ | 22 |
| | $ | — |
|
| Non-cash financing activities | | | |
| Settlement of tangible equity units | $ | — |
| | $ | 300 |
|
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| millions | 2019 |
| | 2018 |
|
| Cash paid (received) | | | |
| Interest, net of amounts capitalized | $ | 371 |
| | $ | 326 |
|
| Income taxes, net of refunds | 18 |
| | 12 |
|
| Non-cash investing activities | | | |
| Fair value of properties and equipment acquired | $ | — |
| | $ | 2 |
|
| Asset retirement cost additions | 71 |
| | 63 |
|
| Accruals of property, plant, and equipment | 781 |
| | 965 |
|
| Net liabilities assumed (divested) in acquisitions and divestitures | — |
| | (25 | ) |
| Non-cash investing and financing activities | | | |
| Finance leases | $ | 6 |
| | $ | — |
|
The following table provides a reconciliation of Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents as reported in the Consolidated Statement of Cash Flows to the line items within the Consolidated Balance Sheets:
|
| | | | | | | | |
| millions | June 30, 2019 | | December 31, 2018 | |
| Cash and cash equivalents | | $ | 1,394 |
| | $ | 1,295 |
|
| Restricted cash and restricted cash equivalents included in Other Assets | | 137 |
| | 134 |
|
| Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents | | $ | 1,531 |
| | $ | 1,429 |
|
|
| | | | | | | | |
| millions | March 31, 2019 | | December 31, 2018 | |
| Cash and cash equivalents | | $ | 2,026 |
| | $ | 1,295 |
|
| Restricted cash and restricted cash equivalents included in Other Assets | | 134 |
| | 134 |
|
| Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents | | $ | 2,160 |
| | $ | 1,429 |
|
Included in cash and cash equivalents is restricted cash and restricted cash equivalents of $100$118 million at March 31,June 30, 2019, and $139 million at December 31, 2018. Total restricted cash and restricted cash equivalents are primarily associated with certain international joint venture operations, payments of future hard-minerals royalty revenues conveyed, like-kind exchanges of property, and a judicially-controlled account related to a Brazilian tax dispute. See Note 18—Contingencies in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.
31 35 | APC 2019 FORM 10-Q
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
17.19. Segment Information |
Anadarko’s business segments are separately managed due to distinct operational differences. On February 28, 2019, Anadarko completed the previously announced contribution and sale of substantially all of its remaining midstream assets to WES. Due to this contribution and sale, the Company will no longer reportreports an Other Midstream segment and will now havehas two reporting segments: Exploration and Production and WES Midstream, which include their respective marketing results. Prior period amounts have been reclassified to conform to the current period’scurrent-period presentation.
The Exploration and Production reporting segment is engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and inis advancing its Mozambique LNG project toward FID.to the construction phase after announcing FID on June 18, 2019. The WES Midstream reporting segment is engaged in gathering, compressing, treating, processing, and transporting of natural gas; gathering, stabilizing, and transporting of oil and NGLs; and gathering and disposing of produced water.
To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; interest expense; DD&A; exploration expense; gains (losses) on divestitures, net; impairments; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; certain items not related to the Company’s normal operations; and less net income (loss) attributable to noncontrolling interests.
The Company’s definition of Adjusted EBITDAX excludes gains (losses) on divestitures, net and exploration expense as they are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income (loss) attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.
Management believes Adjusted EBITDAX provides information useful in assessing the Company’s operating and financial performance across periods. Adjusted EBITDAX as defined by Anadarko may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| millions | 2019 |
| | 2018 |
|
| Income (loss) before income taxes | $ | 262 |
| | $ | 300 |
|
| Interest expense | 253 |
| | 228 |
|
| DD&A | 1,081 |
| | 990 |
|
| Exploration expense | 49 |
| | 168 |
|
| (Gains) losses on divestitures, net | 5 |
| | 24 |
|
| Impairments | — |
| | 19 |
|
| Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives | 316 |
| | (27 | ) |
| Reorganization-related charges | 18 |
| | — |
|
| Less net income (loss) attributable to noncontrolling interests | 111 |
| | 53 |
|
| Consolidated Adjusted EBITDAX | $ | 1,873 |
| | $ | 1,649 |
|
|
| | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
| millions | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Income (loss) before income taxes | $ | (736 | ) | | $ | 142 |
| | $ | (474 | ) | | $ | 442 |
|
| Interest expense | 249 |
| | 237 |
| | 502 |
| | 465 |
|
| DD&A | 1,161 |
| | 1,003 |
| | 2,242 |
| | 1,993 |
|
| Exploration expense | 90 |
| | 94 |
| | 139 |
| | 262 |
|
| (Gains) losses on divestitures, net | (6 | ) | | (52 | ) | | (1 | ) | | (28 | ) |
| Impairments | — |
| | 128 |
| | — |
| | 147 |
|
| Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives | 255 |
| | 267 |
| | 571 |
| | 240 |
|
| Reorganization-related charges | 15 |
| | — |
| | 33 |
| | — |
|
| Merger transaction costs | 1,042 |
| | — |
| | 1,042 |
| | — |
|
| Less net income (loss) attributable to noncontrolling interests | 80 |
| | (12 | ) | | 191 |
| | 41 |
|
| Consolidated Adjusted EBITDAX | $ | 1,990 |
| | $ | 1,831 |
| | $ | 3,863 |
| | $ | 3,480 |
|
APC 2019 FORM 10-Q | 32 36
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
17.19. Segment Information (Continued) |
Information presented below as “Other and Intersegment Eliminations” includes corporate costs, margin on sales of third-party commodity purchases, deficiency fee expenses, results from hard-minerals royalties, net cash from settlement of commodity derivatives, and net income (loss) attributable to noncontrolling interests. The following summarizes selected financial information for Anadarko’s reporting segments:
| | | millions | Exploration
& Production | | WES Midstream | | Other and
Intersegment
Eliminations | |
| Total |
| Exploration
& Production | | WES Midstream | | Other and
Intersegment
Eliminations | | | Total |
|
| Three Months Ended March 31, 2019 | | | | | | | | | |
| Three Months Ended June 30, 2019 | | | | | | | | | |
| Sales revenues | | $ | 2,606 |
| | $ | 499 |
| | $ | 21 |
| | $ | 3,126 |
| | $ | 2,852 |
| | $ | 492 |
| | $ | 12 |
| | $ | 3,356 |
|
| Intersegment revenues | | 51 |
| | 172 |
| | (223 | ) | | — |
| | 40 |
| | 193 |
| | (233 | ) | | — |
|
| Other | | 8 |
| | 58 |
| | 31 |
| | 97 |
| | (4 | ) | | 70 |
| | 14 |
| | 80 |
|
Total revenues and other (1) | | 2,665 |
| | 729 |
| | (171 | ) | | 3,223 |
| | 2,888 |
| | 755 |
| | (207 | ) | | 3,436 |
|
Operating costs and expenses (2) | | 992 |
| | 337 |
| | (89 | ) | | 1,240 |
| | 987 |
| | 381 |
| | (4 | ) | | 1,364 |
|
| Net cash from settlement of commodity derivatives | | — |
| | — |
| | (6 | ) | | (6 | ) | | — |
| | — |
| | — |
| | — |
|
Other (income) expense, net (3) | | — |
| | (36 | ) | | 38 |
| | 2 |
| | — |
| | (59 | ) | | 62 |
| | 3 |
|
| Net income (loss) attributable to noncontrolling interests | | — |
| | — |
| | 111 |
| | 111 |
| | — |
| | — |
| | 80 |
| | 80 |
|
| Total expenses and other | | 992 |
| | 301 |
| | 54 |
| | 1,347 |
| | 987 |
| | 322 |
| | 138 |
| | 1,447 |
|
| Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement | | — |
| | — |
| | (3 | ) | | (3 | ) | | — |
| | — |
| | 1 |
| | 1 |
|
| Adjusted EBITDAX | | $ | 1,673 |
| | $ | 428 |
| | $ | (228 | ) | | $ | 1,873 |
| | $ | 1,901 |
| | $ | 433 |
| | $ | (344 | ) | | $ | 1,990 |
|
| | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2018 | | | | | | | | | |
| Three Months Ended June 30, 2018 | | | | | | | | | |
| Sales revenues | | $ | 2,656 |
|
| $ | 355 |
| | $ | 15 |
|
| $ | 3,026 |
| | $ | 2,772 |
| | $ | 358 |
| | $ | 38 |
| | $ | 3,168 |
|
| Intersegment revenues | | 10 |
|
| 153 |
| | (163 | ) |
| — |
| | 14 |
| | 160 |
| | (174 | ) | | — |
|
| Other | | (9 | ) |
| 37 |
| | 15 |
|
| 43 |
| | 3 |
| | 39 |
| | 29 |
| | 71 |
|
Total revenues and other (1) | | 2,657 |
|
| 545 |
| | (133 | ) |
| 3,069 |
| | 2,789 |
| | 557 |
| | (107 | ) | | 3,239 |
|
Operating costs and expenses (2) | | 870 |
|
| 233 |
| | 214 |
|
| 1,317 |
| | 900 |
| | 246 |
| | 101 |
| | 1,247 |
|
| Net cash from settlement of commodity derivatives | | — |
|
| — |
| | 68 |
|
| 68 |
| | — |
| | — |
| | 170 |
| | 170 |
|
Other (income) expense, net | | — |
|
| — |
| | (12 | ) |
| (12 | ) | | — |
| | — |
| | 4 |
| | 4 |
|
| Net income (loss) attributable to noncontrolling interests | | — |
|
| — |
| | 53 |
|
| 53 |
| | — |
| | — |
| | (12 | ) | | (12 | ) |
| Total expenses and other | | 870 |
|
| 233 |
| | 323 |
|
| 1,426 |
| | 900 |
| | 246 |
| | 263 |
| | 1,409 |
|
| Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement | | — |
|
| — |
| | 6 |
|
| 6 |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Adjusted EBITDAX | | $ | 1,787 |
|
| $ | 312 |
| | $ | (450 | ) |
| $ | 1,649 |
| | $ | 1,889 |
| | $ | 311 |
| | $ | (369 | ) | | $ | 1,831 |
|
| |
(1) | Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX. |
| |
(2) | Operating costs and expenses excludes exploration expense, DD&A, impairments, reorganization-related charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX. |
| |
(3) | Other (income) expense, net excludes reorganization-related charges since these expenses are excluded from Adjusted EBITDAX. |
33 37 | APC 2019 FORM 10-Q
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
17.19. Segment Information (Continued) |
|
| | | | | | | | | | | | | | | | |
| millions | Exploration
& Production | | WES Midstream | | Other and
Intersegment
Eliminations | |
| Total |
|
| Six Months Ended June 30, 2019 | | | | | | | | |
| Sales revenues | | $ | 5,458 |
| | $ | 992 |
| | $ | 32 |
| | $ | 6,482 |
|
| Intersegment revenues | | 91 |
| | 365 |
| | (456 | ) | | — |
|
| Other | | 4 |
| | 132 |
| | 41 |
| | 177 |
|
Total revenues and other (1) | | 5,553 |
| | 1,489 |
| | (383 | ) | | 6,659 |
|
Operating costs and expenses (2) | | 1,979 |
| | 723 |
| | (98 | ) | | 2,604 |
|
| Net cash from settlement of commodity derivatives | | — |
| | — |
| | (6 | ) | | (6 | ) |
Other (income) expense, net (3) | | — |
| | (95 | ) | | 100 |
| | 5 |
|
| Net income (loss) attributable to noncontrolling interests | | — |
| | — |
| | 191 |
| | 191 |
|
| Total expenses and other | | 1,979 |
| | 628 |
| | 187 |
| | 2,794 |
|
| Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement | | — |
| | — |
| | (2 | ) | | (2 | ) |
| Adjusted EBITDAX | | $ | 3,574 |
| | $ | 861 |
| | $ | (572 | ) | | $ | 3,863 |
|
| | | | | | | | | |
| Six Months Ended June 30, 2018 | | | | | | | | |
| Sales revenues | | $ | 5,428 |
|
| $ | 706 |
| | $ | 60 |
|
| $ | 6,194 |
|
| Intersegment revenues | | 24 |
|
| 313 |
| | (337 | ) |
| — |
|
| Other | | (6 | ) |
| 80 |
| | 40 |
|
| 114 |
|
Total revenues and other (1) | | 5,446 |
|
| 1,099 |
| | (237 | ) |
| 6,308 |
|
Operating costs and expenses (2) | | 1,770 |
|
| 476 |
| | 318 |
|
| 2,564 |
|
| Net cash from settlement of commodity derivatives | | — |
|
| — |
| | 238 |
|
| 238 |
|
| Other (income) expense, net | | — |
|
| — |
| | (8 | ) |
| (8 | ) |
| Net income (loss) attributable to noncontrolling interests | | — |
|
| — |
| | 41 |
|
| 41 |
|
| Total expenses and other | | 1,770 |
|
| 476 |
| | 589 |
|
| 2,835 |
|
| Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement | | — |
|
| — |
| | 7 |
|
| 7 |
|
| Adjusted EBITDAX | | $ | 3,676 |
|
| $ | 623 |
| | $ | (819 | ) |
| $ | 3,480 |
|
| |
(1) | Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX. |
| |
(2) | Operating costs and expenses excludes exploration expense, DD&A, impairments, reorganization-related charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX. |
| |
(3) | Other (income) expense, net excludes reorganization-related charges since these expenses are excluded from Adjusted EBITDAX. |
|
| | |
| FINANCIAL STATEMENTS
FOOTNOTES | |
|
|
| 19. Segment Information (Continued) |
The following summarizes selected financial information for Anadarko’s reporting segments:
|
| | | | | | | | | | | | | | | | |
| millions | Exploration
& Production | | WES Midstream | | Other and
Intersegment
Eliminations | | Total | |
| June 30, 2019 | | | | | | | | |
| Net properties and equipment | | $ | 18,306 |
| | $ | 8,794 |
| | $ | 1,991 |
| | $ | 29,091 |
|
Capital expenditures (1) | | $ | 1,879 |
| | $ | 571 |
| | $ | 103 |
| | $ | 2,553 |
|
| Goodwill | | $ | 4,343 |
| | $ | 446 |
| | $ | — |
| | $ | 4,789 |
|
| | | | | | | | | |
| December 31, 2018 | | | | | | | | |
| Net properties and equipment | | $ | 18,276 |
| | $ | 8,410 |
| | $ | 1,929 |
| | $ | 28,615 |
|
Capital expenditures (1) | | $ | 4,103 |
| | $ | 1,912 |
| | $ | 170 |
| | $ | 6,185 |
|
| Goodwill | | $ | 4,343 |
| | $ | 446 |
| | $ | — |
| | $ | 4,789 |
|
|
| | | | | | | | | | | | | | | | |
| millions | Exploration
& Production | | WES Midstream | | Other and
Intersegment
Eliminations | | Total | |
| March 31, 2019 | | | | | | | | |
| Net properties and equipment | | $ | 18,342 |
| | $ | 8,630 |
| | $ | 1,964 |
| | $ | 28,936 |
|
Capital expenditures (1) | | $ | 922 |
| | $ | 315 |
| | $ | 59 |
| | $ | 1,296 |
|
| Goodwill | | $ | 4,343 |
| | $ | 446 |
| | $ | — |
| | $ | 4,789 |
|
| | | | | | | | | |
| December 31, 2018 | | | | | | | | |
| Net properties and equipment | | $ | 18,267 |
| | $ | 8,410 |
| | $ | 1,938 |
| | $ | 28,615 |
|
Capital expenditures (1) | | $ | 4,103 |
| | $ | 1,912 |
| | $ | 170 |
| | $ | 6,185 |
|
| Goodwill | | $ | 4,343 |
| | $ | 446 |
| | $ | — |
| | $ | 4,789 |
|
| |
(1) | WES Midstream includes $49 million at March 31,June 30, 2019, and $734 million at December 31, 2018, of capitalized costs incurred by Anadarko prior to the contribution and sale of midstream assets to WES. |
39 | APC 2019 FORM 10-Q | 34
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
INDEX | |
Item 2. 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-Q in Part I, Item 1; the information set forth in the Risk Factors under Part II, Item 1A; the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018; and the information set forth in the Risk Factors under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.
35 | APC 2019 FORM 10-Q | 40
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
MANAGEMENT OVERVIEW | |
Anadarko’s strategic objectives are to explore for, develop, and commercialize resources globally; ensure health, safety, and environmental excellence; focus on financial discipline, flexibility, and value creation; and demonstrate the Company’s core values in all its business activities. The Company’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly dependent on commodity prices, which affect the value the Company receives from its sales of oil, natural gas, and NGLs.
On April 11, 2019, the Company entered into the Chevron Merger Agreement pursuant to which, and subject to the conditions of the agreement, all outstanding shares of Anadarko will be acquired by Chevron in a stock and cash transaction valued at $33 billion, or $65.00 per share, as of the announcement date. Under the terms of the Chevron Merger Agreement, Anadarko stockholders will receive 0.3869 of a share of Chevron common stock and $16.25 in cash for each Anadarko share. The transaction was approved by the Boards of Directors of both companies. On May 6, 2019, Anadarko announced that the Board unanimously determined that the Occidental Proposal constituted a “Superior Proposal” as defined in the Chevron Merger Agreement. Under the terms of the Occidental Proposal, Occidental would acquire Anadarko for consideration consisting of $59.00 in cash and 0.2934 of a share of Occidental common stock per share of Anadarko common stock. Anadarko has notified Chevron that (i) the Board has unanimously determined that the Occidental Proposal constitutes a "Superior Proposal" and (ii) after complying with its obligations to Chevron under the Chevron Merger Agreement, Anadarko intends to terminate the Chevron Merger Agreement in order to enter into a definitive merger agreement with Occidental in connection with the Occidental Proposal. Pursuant to the Chevron Merger Agreement, Chevron has the right, during the four business day period ending on May 10, 2019, which may be extended in accordance with the terms of the Chevron Merger Agreement, to propose revisions to the terms of the Chevron Merger Agreement, or to make another proposal. If Anadarko terminates the Chevron Merger Agreement in order to enter into a definitive agreement with respect to the Occidental Proposal, Anadarko will pay Chevron a $1.0 billion termination fee as required by the Chevron Merger Agreement. The Chevron Merger Agreement remains in effect unless and until terminated, and accordingly, the Board reaffirms its existing recommendation of the transaction with Chevron at this time. Either transaction would be subject to Anadarko stockholder approval, regulatory approvals, and other customary closing conditions.
On February 28, 2019, Anadarko completed the previously announced contribution and sale of substantially all of its midstream assets, which consisted of oil infrastructure assets in the DJ basin and oil and water infrastructure assets in the Delaware basin, to WES Operating for $4.0 billion, with $2.0 billion of cash proceeds and $2.0 billion in WES Operating common units. This transaction is expected to increase cash distributions paid by WES to Anadarko in 2019 and reduce Anadarko’s future midstream capital funding requirements. Immediately after the asset contribution and sale, a wholly owned subsidiary of WES merged with and into WES Operating, with WES Operating continuing as the surviving entity and a subsidiary of WES. The merger is expected to simplify the midstream structure, lower the weighted-average cost of capital for WES through the elimination of incentive distribution rights, and increase the overall trading liquidity of WES.
The Company remains committed to investing within cash flow in a $50 oil-price environment. Anadarko is focused on capital efficiency and maximizing cash flow generation, 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 portion of its cash flow generated from its Gulf of Mexico, Algeria, Ghana, and DJ basin assets to fund investments in other assets that generate attractive cash returns.
In the Delaware basin, the Company continues to build out one of the most expansive and integrated infrastructure positions in the region as it transitions toward multi-well pad development, primarily in Reeves and Loving counties. The Company also continues to leverage its minerals-interest ownership and extensive infrastructure position in the DJ basin to deliver development wells with attractive rates of return. In the Gulf of Mexico, the Company is conducting operations that are focused toward high-return oil development opportunities near the Company’s expansive infrastructure.
The Company has returned capital directly to its investors through its quarterly cash dividend, its authorized Share-Repurchase Program, and its debt-reduction program. Since the Share-Repurchase Program was announced in 2017, the Company has repurchased 65 million shares of its common stock for $3.75 billion. InAdditionally, since the first quarterannouncement of 2019, Anadarko repaid $600 million of debt at maturity and redeemed an additional $300 million of debt prior to maturity, bringing total repayments under the debt-reduction program toin 2018, the Company has completed total repayments of $1.5 billion. No additional share repurchases under the Share-Repurchase Program or debt retirements are anticipated pursuant to the terms of the Occidental Merger Agreement.
Merger On April 11, 2019, the Company entered into the Chevron Merger Agreement. On April 24, 2019, Occidental announced a proposal to acquire Anadarko and further revised its proposal on May 5, 2019. On May 6, 2019, Anadarko announced that its Board had unanimously determined that the Occidental proposal was a “Superior Proposal” as defined in the Chevron Merger Agreement and, on May 9, 2019, provided Chevron a notice terminating the Chevron Merger Agreement. Pursuant to the terms of the Chevron Merger Agreement, the Company paid the Chevron Merger Termination Fee of $1.0 billion. Also on May 9, 2019, the Company entered into the Occidental Merger Agreement, which provides that, among other things, and subject to the terms and conditions of the Occidental Merger Agreement, a wholly owned subsidiary of Occidental will be merged with and into Anadarko, with Anadarko continuing as the surviving corporation and a wholly owned subsidiary of Occidental. Pursuant to the Occidental Merger Agreement, at the effective time of the Occidental Merger and subject to potential further adjustments as specified in the Occidental Merger Agreement, Anadarko stockholders will receive $59.00 in cash and 0.2934 of a share of Occidental common stock for each share of Anadarko common stock, plus cash in lieu of any fractional Occidental shares that otherwise would have been issued. The transaction was approved by the Boards of Directors of both companies. The Occidental Merger is subject to Anadarko stockholder approval and other customary closing conditions. Anadarko is holding a special meeting of its stockholders on August 8, 2019, for holders of record as of July 11, 2019, to vote on the proposal necessary to complete the Occidental Merger. Assuming all closing conditions are satisfied, including obtaining the requisite approval from the Anadarko stockholders, Occidental and Anadarko expect the Occidental Merger to close shortly after the special meeting of Anadarko stockholders.
In addition to the Chevron Merger Termination Fee, Anadarko has incurred merger transaction costs of $42 million as of June 30, 2019.
Mozambique FID On June 18, 2019, the Company and its co-venturers in Mozambique’s Offshore Area 1 announced FID on the Anadarko-led Area 1 Mozambique LNG project. This official declaration of FID confirms the Golfinho/Atum Plan of Development is now effective with notice provided to the Government of Mozambique that all conditions precedent have been satisfied, and the project can now advance to the construction phase. The Mozambique LNG project initially consists of two LNG trains with total nameplate capacity of 12.88 MTPA to support the development of the Golfinho/Atum fields located entirely within Offshore Area 1. Subsequent to FID, the Company began entering into various long-term contractual commitments pertaining to LNG activities in Mozambique. As of June 30, 2019, the gross aggregate future payments under these contracts was approximately $2.0 billion, of which $507 million is net to Anadarko. On July 26, 2019, Anadarko issued a Notice-to-Proceed to the onshore engineering, procurement, and construction contractor for the Mozambique LNG project, resulting in additional obligations with gross aggregate future payments of approximately $8.0 billion, of which $2.1 billion is net to Anadarko. See Note 12—Commitments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.
41 | APC 2019 FORM 10-Q | 36
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
MANAGEMENT OVERVIEW | |
Midstream Asset Sale and WES Merger On February 28, 2019, Anadarko completed the previously announced contribution and sale of substantially all of its midstream assets, which consisted mainly of oil infrastructure assets in the DJ basin and oil and water infrastructure assets in the Delaware basin, to WES Operating for $4.0 billion, with $2.0 billion of cash proceeds and $2.0 billion of WES Operating common units. Immediately after the asset contribution and sale, a wholly owned subsidiary of WES merged with and into WES Operating, with WES Operating continuing as the surviving entity and a subsidiary of WES.
|
|
Significant FirstSecond Quarter 2019 Operating and Financial Activities |
Total Company
| |
| – | The Company’s oil sales volume averaged 412434 MBbls/d in the firstsecond quarter of 2019, representing an 11%a 19% increase from the firstsecond quarter of 2018, primarily due to increased sales volume from the Delaware basinand DJ basins, Algeria, Ghana, and the Gulf of Mexico. |
| |
| – | The Company’s overall sales-volume product mix in the firstsecond quarter of 2019 is 58%59% oil and 73%74% liquids. |
U.S. Onshore
| |
| – | Total sales volume averaged 465484 MBOE/d in the firstsecond quarter of 2019, representing a 15%16% increase from the firstsecond quarter of 2018, and oil sales volume averaged 195207 MBbls/d in the firstsecond quarter of 2019, representing a 22%23% increase from the firstsecond quarter of 2018, primarily due to continued drilling and completion activities and midstream infrastructure additions. |
| |
– | The second train at the WES-owned Mentone natural-gas processing plant in the Delaware basin was placed in service, adding 200 MMcf/d of natural-gas processing capacity to the West Texas Complex.
|
Gulf of Mexico
| |
| – | Oil sales volume averaged 138130 MBbls/d in the firstsecond quarter of 2019, representing a 9%14% increase from the firstsecond quarter of 2018, primarily due to new wells coming online at Holstein, increased well performance at Horn Mountain, and Holstein, plannedlower downtime at various platforms in 2019 compared to 2018, and lower-than-expected downtime at various platforms in 2019, partially offset by natural production declines. |
Ghana
| |
| – | In the TEN field, drilling operations concluded on a production well, and a previously drilled water injection well was completed and brought online.online, and another water injection well was drilled. |
| |
| – | In the Jubilee field, the operator drilleddrilling operations were concluded on a water injectorproduction well and drilling operations are ongoing for an additional production well.a previously drilled water injection well was completed and brought online. |
Mozambique
| |
| – | Anadarko and its Area 1 co-venturers executed two additional long-term sale and purchase agreements with Bharat Gas Resources Ltd., a wholly owned subsidiary of Bharat Petroleum Corporation Ltd. of India, and Pertamina,announced FID on the state-owned oil and gas company of Indonesia, each for 1.0 MTPA, bringing total contracted volume to approximately 9.5 MTPA, which satisfies the contracted offtake volume required for FID.Anadarko-led Area 1 Mozambique LNG project. |
| |
| – | As of June 30, 2019, Anadarko and its Area 1 co-venturers were designated first mover byhave successfully secured 11.1 MTPA of long-term LNG sales with key buyers in Asia and Europe, including a 17-year sale and purchase agreement with JERA Co., Inc. and CPC Corporation, Taiwan for 1.6 MTPA announced in May 2019. All of the Governmentexecuted long-term SPAs are now effective, with total contracted volume representing 86% of Mozambique forthe plant’s nameplate capacity. |
| |
| – | The Company issued a Notice-to-Proceed to the offshore engineering, procurement, construction, and installation contractor shortly after FID and issued a Notice-to-Proceed to the onshore LNG project. This enables Anadarko, as operator of Area 1, to construct the shared marine facilities, on behalf of the Area 1engineering, procurement, and Area 4 projects.construction contractor in July 2019. |
| |
| – | The Company is working to finalize project finance arrangements and has received commitments fromsite preparation activities continue as crews progress the majorityconstruction of lenders. Additionally, final partnerthe resettlement village, the camp expansion, the airstrip, and government-related approvals are progressing as the Company expects to announce a final investment decision on June 18, 2019.Palma-Afungi Highway. |
Financial
| |
| – | The Company generated $1.1 billion$776 million of cash flow from operations and ended the firstsecond quarter of 2019 with $2.0$1.4 billion of cash. |
| |
| – | ThePursuant to the terms of the Chevron Merger Agreement, the Company retired $900 millionpaid the Chevron Merger Termination Fee of debt during the first quarter of 2019.$1.0 billion. |
37 | APC 2019 FORM 10-Q | 42
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| millions except per-share amounts | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Oil, natural-gas, and NGL sales | $ | 2,656 |
| | $ | 2,666 |
| $ | 2,891 |
| | $ | 2,786 |
| | $ | 5,547 |
| | $ | 5,452 |
|
| Gathering, processing, and marketing sales | 470 |
| | 360 |
| 465 |
| | 382 |
| | 935 |
| | 742 |
|
| Gains (losses) on divestitures and other, net | 92 |
| | 19 |
| 86 |
| | 123 |
| | 178 |
| | 142 |
|
| Revenues and other | $ | 3,218 |
| | $ | 3,045 |
| $ | 3,442 |
| | $ | 3,291 |
| | $ | 6,660 |
| | $ | 6,336 |
|
Costs and expenses | 2,384 |
| | 2,494 |
| 3,657 |
| | 2,472 |
| | 6,041 |
| | 4,966 |
|
| Other (income) expense | 572 |
| | 251 |
| 521 |
| | 677 |
| | 1,093 |
| | 928 |
|
| Income tax expense (benefit) | 166 |
| | 126 |
| 209 |
| | 125 |
| | 375 |
| | 251 |
|
| Net income (loss) attributable to common stockholders | $ | (15 | ) | | $ | 121 |
| $ | (1,025 | ) | | $ | 29 |
| | $ | (1,040 | ) | | $ | 150 |
|
| Net income (loss) per common share attributable to common stockholders—diluted | $ | (0.03 | ) | | $ | 0.22 |
| $ | (2.09 | ) | | $ | 0.05 |
| | $ | (2.13 | ) | | $ | 0.28 |
|
| Average number of common shares outstanding—diluted | 490 |
| | 519 |
| 491 |
| | 505 |
| | 491 |
| | 512 |
|
| |
(1) | Includes the Chevron Merger Termination Fee of $1.0 billion. See Note 1—Summary of Significant Accounting Policiesin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information on the Occidental Merger. |
The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the three months ended March 31,June 30, 2019,” refer to the comparison of the three months ended March 31,June 30, 2019, to the three months ended March 31,June 30, 2018, and any increases or decreases “for the six months ended June 30, 2019,” refer to the comparison of the six months ended June 30, 2019, to the six months ended June 30, 2018. The primary factors that affect the Company’s results of operations include commodity prices for oil, natural gas, and NGLs; sales volume; the cost of finding and developing such reserves; and operating costs.
43 | APC 2019 FORM 10-Q | 38
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
REVENUES AND SALES VOLUME
E&P Sales Revenues by Product
The table below illustrates the effects of changes in prices and sales volume. Price changes for the three and six months ended March 31,June 30, 2019 were primarily due to lower oil and NGL prices in 2019. Sales volume changes for the three and six months ended March 31,June 30, 2019 primarily included increases associated with continued drilling and completion activities in the Delaware and DJ basins.
Total E&P Sales Revenues
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
The following provides Anadarko’s sales volume for the three and six months ended March 31:June 30:
| | | | Barrels of Oil Equivalent (MMBOE) | | Barrels of Oil Equivalent per Day (MBOE/d) | Three Months Ended | | Six Months Ended |
| | 2019 |
| 2018 |
| | 2019 |
| 2018 |
| June 30, | | June 30, |
| | | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Barrels of Oil Equivalent (MMBOE) | | | | | | | | |
| United States | 56 |
| 50 |
| | 631 |
| 555 |
| 59 |
| | 50 |
| | 115 |
| | 100 |
|
| International | 8 |
| 8 |
| | 84 |
| 88 |
| 9 |
| | 8 |
| | 17 |
| | 16 |
|
| Total | 64 |
| 58 |
| | 715 |
| 643 |
| |
| Total barrels of oil equivalent | | 68 |
| | 58 |
| | 132 |
| | 116 |
|
| | | | | | | | | |
| Barrels of Oil Equivalent per Day (MBOE/d) | | | | | | | | |
| United States | | 642 |
| | 552 |
| | 636 |
| | 553 |
|
| International | | 102 |
| | 85 |
| | 93 |
| | 87 |
|
| Total barrels of oil equivalent per day | | 744 |
| | 637 |
| | 729 |
| | 640 |
|
Sales volume represents actual production volume adjusted for changes in commodity inventories as well as natural-gas production volume provided to satisfy a commitment under the Jubilee development plan in Ghana. The Company has derivative instruments in place to reduce the price risk associated with future production. For additional information, see Note 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. Production of oil, natural gas, and NGLs is usually not affected by seasonal swings in demand.
39 45 | APC 2019 FORM 10-Q
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
|
|
| Oil Sales Revenues, Volume, and Average Prices |
Oil Sales Revenues
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Oil sales revenues (millions) | $ | 2,096 |
| | $ | 2,127 |
| $ | 2,470 |
| | $ | 2,265 |
| | $ | 4,566 |
| | $ | 4,392 |
|
| | | | | | | | | | | |
| Average price per barrel | | | | | | | | | | |
| United States | $ | 55.14 |
| | $ | 62.58 |
| $ | 60.60 |
| | $ | 66.94 |
| | $ | 57.90 |
| | $ | 64.75 |
|
| International | 62.33 |
| | 67.39 |
| 68.88 |
| | 73.70 |
| | 65.96 |
| | 70.51 |
|
| Total | $ | 56.51 |
| | $ | 63.66 |
| $ | 62.45 |
| | $ | 68.43 |
| | $ | 59.58 |
| | $ | 66.03 |
|
| | | | | | | | | | | |
| Sales volume (MMBbls) | | | | | | | | | | |
| United States | 29 |
| | 25 |
| 32 |
| | 27 |
| | 61 |
| | 52 |
|
| International | 8 |
| | 8 |
| 8 |
| | 7 |
| | 16 |
| | 15 |
|
| Total | 37 |
| | 33 |
| 40 |
| | 34 |
| | 77 |
| | 67 |
|
| | | | | | | | | | | |
| Sales volume per day (MBbls/d) | | | | | | | | | | |
| United States | 333 |
| | 288 |
| 337 |
| | 284 |
| | 335 |
| | 286 |
|
| International | 79 |
| | 83 |
| 97 |
| | 80 |
| | 88 |
| | 82 |
|
| Total | 412 |
| | 371 |
| 434 |
| | 364 |
| | 423 |
| | 368 |
|
Oil Prices
The average oil price received decreased for the three and six months ended March 31,June 30, 2019, primarily due to concerns of oil demand weakness from a slowing global economy.
APC 2019 FORM 10-Q | 40 46
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
Oil Sales Volume
2019 vs. 2018 The Company’s oil sales volume increased by 4170 MBbls/d for the three months ended March 31,June 30, 2019, and 55 MBbls/d for the six months ended June 30, 2019, primarily due to the following:
U.S. Onshore
| |
| – | Sales volume for the Delaware basin increased by 3020 MBbls/d for the three months ended March 31,June 30, 2019, and 24 MBbls/d for the six months ended June 30, 2019, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2019. |
| |
| – | Sales volume for the DJ basin increased by 12 MBbls/d for the three months ended June 30, 2019, and 8 MBbls/d for the six months ended June 30, 2019, primarily due to continued drilling and completion activities in 2019. |
Gulf of Mexico
| |
| – | Sales volume for the Gulf of Mexico increased by 1015 MBbls/d for the three months ended March 31,June 30, 2019, and13 MBbls/d for the six months ended June 30, 2019, primarily due to new wells coming online at Holstein, increased well performance at Horn Mountain, and Holstein, planned downtime at various platforms in 2018, and lower-than-expectedlower downtime at various platforms in 2019 compared to 2018, partially offset by natural production declines. |
International
| |
| – | Sales volume for Algeria increased by 68 MBbls/d for the three months ended March 31,June 30, 2019, and 6 MBbls/d for the six months ended June 30, 2019, primarily due to the size and timing of liftings. |
| |
| – | Sales volume for Ghana decreasedincreased by 109 MBbls/d for the three months ended March 31,June 30, 2019, primarily due to the timing of liftings. |
41 47 | APC 2019 FORM 10-Q
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
|
|
| Natural-Gas Sales Revenues, Volume, and Average Prices |
Natural-Gas Sales Revenues
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Natural-gas sales revenues (millions) | $ | 320 |
| | $ | 247 |
| $ | 205 |
| | $ | 203 |
| | $ | 525 |
| | $ | 450 |
|
| | | | | | | | | | | |
| Average price per Mcf | $ | 3.09 |
| | $ | 2.61 |
| $ | 1.93 |
| | $ | 2.15 |
| | $ | 2.50 |
| | $ | 2.38 |
|
| | | | | | | | | | | |
Sales volume (Bcf) (1) | 104 |
| | 95 |
| 106 |
| | 94 |
| | 210 |
| | 189 |
|
Sales volume per day (MMcf/d) (1) | 1,151 |
| | 1,051 |
| 1,167 |
| | 1,037 |
| | 1,159 |
| | 1,044 |
|
| |
(1) | Natural-gas sales volume primarily originates in the United States. |
Natural-Gas Prices
The average natural-gas price received increased for the threesix months ended March 31,June 30, 2019, primarily due to increased residential and commercial demand from colder than normalcolder-than-normal temperatures in the western U.S. and improved price differentials in the DJ basin.basin through April 2019. The average natural-gas price received decreased for the three months ended June 30, 2019, due to lower electric generation demand and wider DJ and Delaware basin differentials during the last two months of the second quarter.
Natural-Gas Sales Volume
2019 vs. 2018The Company’s natural-gas sales volume increased by 100130 MMcf/d for the three months ended March 31,June 30, 2019, and 115 MMcf/d for the six months ended June 30, 2019, primarily due to continued drilling and completion activities in the Delaware and DJ basins in 2019.
APC 2019 FORM 10-Q | 42 48
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
|
|
| Natural-Gas Liquids Sales Revenues, Volume, and Average Prices |
Natural-Gas Liquids Sales Revenues
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Natural-gas liquids sales revenues (millions) | $ | 240 |
| | $ | 292 |
| $ | 216 |
| | $ | 318 |
| | $ | 456 |
| | $ | 610 |
|
| | | | | | | | | | | |
| Average price per barrel | $ | 24.11 |
| | $ | 33.63 |
| $ | 20.63 |
| | $ | 34.88 |
| | $ | 22.33 |
| | $ | 34.27 |
|
| | | | | | | | | | | |
Sales volume (MMBbls) (1) | 10 |
| | 9 |
| 10 |
| | 9 |
| | 20 |
| | 18 |
|
Sales volume (MBbls/d) (1) | 111 |
| | 97 |
| 115 |
| | 100 |
| | 113 |
| | 98 |
|
| |
(1) | Approximately 95% of NGL sales volume was fromoriginates in the United States. |
NGL Prices
The average NGL price received decreased for the three and six months ended March 31,June 30, 2019, primarily due to higher overall NGL production as a result of infrastructure additions and lower consumption stemming from both reduced chemical plant utilization and stagnant LPG exports.
NGL Sales Volume
2019 vs. 2018 The Company’s NGL sales volume increased by 1415 MBbls/d for the three and six months ended March 31,June 30, 2019, primarily due to continued drilling and completion activities and midstream infrastructure additions in the Delaware basin in 2019.
43 49 | APC 2019 FORM 10-Q
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
|
|
| Gathering, Processing, and Marketing |
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Gathering, processing, and marketing sales | $ | 470 |
| | $ | 360 |
| $ | 465 |
| | $ | 382 |
| | $ | 935 |
| | $ | 742 |
|
| Gathering, processing, and marketing expense | 256 |
| | 237 |
| 274 |
| | 252 |
| | 530 |
| | 489 |
|
| Gathering, processing, and marketing, net | $ | 214 |
| | $ | 123 |
| $ | 191 |
| | $ | 130 |
| | $ | 405 |
| | $ | 253 |
|
Gathering and processing sales include 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 WES. The net margin from the sale of NGLs and residue gas for service customers when WES is acting as an agent is also included. Gathering and processing expense includes the cost of third-party natural gas purchased and processed by WES as well as transportation and other operating expenses related to WES’s costs to perform gathering and processing activities.
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.
Total gathering, processing, and marketing, net increased by $91$61 million for the three months ended March 31,June 30, 2019, and by $152 million for the six months ended June 30, 2019, primarily due to increased throughput volume at the West Texas Complex and the DJ Basin Complex coupled with an increaseas a result of increased drilling activities in oil marketing margins primarily due tothe Delaware basin and increased third-party oil volume purchased and transported toactivity in the Gulf Coast.DJ basin.
|
|
| Gains (Losses) on Divestitures and Other, net |
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Gains (losses) on divestitures, net | $ | (5 | ) | | $ | (24 | ) | $ | 6 |
| | $ | 52 |
| | $ | 1 |
| | $ | 28 |
|
| Other | 97 |
| | 43 |
| 80 |
| | 71 |
| | 177 |
| | 114 |
|
| Gains (losses) on divestitures and other, net | $ | 92 |
| | $ | 19 |
| $ | 86 |
| | $ | 123 |
| | $ | 178 |
| | $ | 142 |
|
Gains (losses) on divestitures and other, net includes gains (losses) on divestitures and other operating revenues, including earnings (losses) from equity investments, hard-minerals royalties, and other revenues.
Earnings (losses) from equity investments increased $43by $15 million for the three months ended March 31,June 30, 2019, and by $58 million for the six months ended June 30, 2019, primarily related to the Company’s investments in midstream joint ventures. During the threesix months ended March 31,June 30, 2018, Anadarko divested certain non-core U.S. onshore and Gulf of Mexico assets. See Note 4—Divestituresin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.
APC 2019 FORM 10-Q | 44 50
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
COSTS AND EXPENSES
The following provides Anadarko’s total costs and expenses for the three and six months ended March 31:June 30:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
| millions | 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Oil and gas operating | $ | 310 |
| | $ | 275 |
| | $ | 599 |
| | $ | 551 |
|
| Oil and gas transportation | 222 |
| | 209 |
| | 444 |
| | 405 |
|
| Exploration | 90 |
| | 94 |
| | 139 |
| | 262 |
|
Gathering, processing, and marketing (1) | 274 |
| | 252 |
| | 530 |
| | 489 |
|
| G&A | 368 |
| | 288 |
| | 635 |
| | 566 |
|
Merger transaction costs (2) | 1,042 |
| | — |
| | 1,042 |
| | — |
|
| DD&A | 1,161 |
| | 1,003 |
| | 2,242 |
| | 1,993 |
|
| Production, property, and other taxes | 182 |
| | 201 |
| | 381 |
| | 391 |
|
Impairments (3) | — |
| | 128 |
| | — |
| | 147 |
|
Other operating expense (4) | 8 |
| | 22 |
| | 29 |
| | 162 |
|
| Total | $ | 3,657 |
| | $ | 2,472 |
| | $ | 6,041 |
| | $ | 4,966 |
|
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| millions | 2019 |
| | 2018 |
|
| Oil and gas operating | $ | 289 |
| | $ | 276 |
|
| Oil and gas transportation | 222 |
| | 196 |
|
| Exploration | 49 |
| | 168 |
|
Gathering, processing, and marketing (1) | 256 |
| | 237 |
|
| G&A | 267 |
| | 278 |
|
| DD&A | 1,081 |
| | 990 |
|
| Production, property, and other taxes | 199 |
| | 190 |
|
| Impairments | — |
| | 19 |
|
| Other operating expense | 21 |
| | 140 |
|
| Total | $ | 2,384 |
| | $ | 2,494 |
|
| |
(1) | See above explanation of gathering, processing, and marketing. |
| |
(2) | Includes Chevron Merger Termination Fee of $1.0 billion, as well as $42 million of additional merger transaction costs. See Note 1—Summary of Significant Accounting Policiesin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information on the Occidental Merger. |
| |
(3) | See Note 5—Impairments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information on impairments. |
| |
(4) | Includes adjustments to contingency accruals, charges for drilling rig idle time, adjustments to drilling rig termination fees, and surface owner payments. |
|
|
| Oil and Gas Operating Expenses |
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
Oil and gas operating (millions) | $ | 289 |
| | $ | 276 |
| $ | 310 |
| | $ | 275 |
| | $ | 599 |
| | $ | 551 |
|
| Oil and gas operating—per BOE | 4.50 |
| | 4.77 |
| 4.57 |
| | 4.75 |
| | 4.54 |
| | 4.76 |
|
Oil and gas operating expense increased by $13$48 million for the threesix months ended March 31,June 30, 2019, primarily due to the following:
| |
| – | higher U.S. onshore costs of $34$63 million, primarily related to increased operated and nonoperated activity in the DJ and Delaware basins |
| |
| – | higher operated costs of $20$33 million in the Gulf of Mexico, primarily related to increased workover activity in the Gulf of Mexico |
| |
| – | lower nonoperated costs of $36$37 million in Ghana, primarily due to insurance reimbursement credits received in 2019 related to Jubilee turret repair |
| |
| – | lower costs of $11$10 million as a result of U.S. onshore and Gulf of Mexico asset divestitures |
The related costs per BOE decreased by $0.27$0.22 for the threesix months ended March 31,June 30, 2019, primarily due to insurance reimbursement credits received in 2019 related to Jubilee turret repair, partially offset by an increased percentage of production in the Delaware basin and higher operated costs in the Gulf of Mexico related to increased workover activity.
45 51 | APC 2019 FORM 10-Q
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
|
|
| Oil and Gas Transportation Expenses |
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Oil and gas transportation (millions) | $ | 222 |
| | $ | 196 |
| $ | 222 |
| | $ | 209 |
| | $ | 444 |
| | $ | 405 |
|
| Oil and gas transportation—per BOE | 3.46 |
| | 3.38 |
| 3.28 |
| | 3.61 |
| | 3.37 |
| | 3.50 |
|
Oil and gas transportation expense increased by $26$39 million for the threesix months ended March 31,June 30, 2019, primarily due to increased sales volumes in the Delaware basin being transported and sold atDJ basins and the Gulf Coast markets. Oil and gasof Mexico, partially offset by lower average transportation expense per BOE remained relatively flat.rates.
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Dry hole expense | $ | — |
| | $ | 53 |
| $ | 3 |
| | $ | 2 |
| | $ | 3 |
| | $ | 55 |
|
| Impairments of unproved properties | — |
|
| 53 |
| 38 |
| | 41 |
| | 38 |
|
| 94 |
|
| Geological and geophysical, exploration overhead, and other expense | 49 |
| | 62 |
| 49 |
| | 51 |
| | 98 |
| | 113 |
|
| Total exploration expense | $ | 49 |
| | $ | 168 |
| $ | 90 |
| | $ | 94 |
| | $ | 139 |
| | $ | 262 |
|
Dry Hole Expense
Dry hole expense for the threesix months ended March 31,June 30, 2018, primarilyincluded $50 million related to unsuccessful drilling activities in the following:Gulf of Mexico.
Impairments of Unproved Properties
For discussion related to impairments of unproved properties, see Note 5—Impairments in the Notes to the Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
|
| | |
– | $49 million related to unsuccessful drilling activities in the GulfMANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| G&A | $ | 267 |
| | $ | 278 |
| $ | 368 |
| | $ | 288 |
| | $ | 635 |
| | $ | 566 |
|
G&A decreasedincreased by $11$80 million for the three months ended March 31,June 30, 2019, and $69 million for the six months ended June 30, 2019, primarily due to a decreaseincreases in the fair value of performance-based unit awards, partially offset by an increase in reorganization-related expenses.expenses, and legal and consulting fees.
The fair value of the performance-based unit awards is calculated using a Monte Carlo simulation that incorporates several variables, including Anadarko’s historical share price and share prices of a predetermined group of peer companies to estimate the future total shareholderstockholder returns of each. Accordingly, future G&A could be higher or lower based on the outputs from the Monte Carlo simulation for the performance-based unit awards.
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
| |
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| DD&A | $ | 1,081 |
| | $ | 990 |
| $ | 1,161 |
| | $ | 1,003 |
| | $ | 2,242 |
| | $ | 1,993 |
|
DD&A expense increased by $91$249 million for the threesix months ended March 31,June 30, 2019, primarily due to the following:
| |
| – | $48179 million increase, primarily due to increased production in the Delaware and DJ basins and the Gulf of Mexico, partially offset by a lower DD&A rate in 2019 primarily driven by increased proved developed reserves in Ghana |
| |
| – | $3371 million increase in straight line depreciation related to additional midstream infrastructure in the Delaware and DJ basins |
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| millions | 2019 |
| | 2018 |
|
| Other operating expense | $ | 21 |
| | $ | 140 |
|
Other operating expense includes adjustments to contingency accruals, charges for drilling rig idle time, adjustments to drilling rig termination fees, and surface owner payments.
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Interest expense | $ | 253 |
| | $ | 228 |
| $ | 249 |
| | $ | 237 |
| | $ | 502 |
| | $ | 465 |
|
(Gains) losses on derivatives, net (1) | 313 |
| | 35 |
| 254 |
| | 436 |
| | 567 |
| | 471 |
|
| Other (income) expense, net | 6 |
| | (12 | ) | 18 |
| | 4 |
| | 24 |
| | (8 | ) |
| Total | $ | 572 |
| | $ | 251 |
| $ | 521 |
| | $ | 677 |
| | $ | 1,093 |
| | $ | 928 |
|
| |
(1) | (Gains) losses on derivatives, net represents the changes in fair value of the Company’s derivative instruments as a result of changes in commodity prices and interest rates, contract modifications, and settlements. See Note 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. |
47 53 | APC 2019 FORM 10-Q
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS | |
|
|
| Income Tax Expense (Benefit) |
| | | | Three Months Ended | Three Months Ended | | Six Months Ended |
| | March 31, | June 30, | | June 30, |
| millions except percentages | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
| | 2019 |
| | 2018 |
|
| Income tax expense (benefit) | $ | 166 |
| | $ | 126 |
| $ | 209 |
| | $ | 125 |
| | $ | 375 |
| | $ | 251 |
|
| Income (loss) before income taxes | 262 |
| | 300 |
| (736 | ) | | 142 |
| | (474 | ) | | 442 |
|
| Effective tax rate | 63 | % | | 42 | % | (28 | )% | | 88 | % | | (79 | )% | | 57 | % |
The Company’s effective tax rate is impacted each year by the relative pre-tax income (loss) earned by the Company’s operations in the U.S., Algeria, and the rest of the world. The Company is subject to statutory tax rates of 38% in Algeria and 35% in Ghana. These higher-taxed foreign operations as well as non-deductible Algerian exceptional profits tax for Algerian income tax purposes generally cause the Company’s effective tax rate to vary significantly from the U.S. corporate tax rate. Additionally, the Company’s effective tax rate 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.
The Company received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox settlement payment in 2015. In April 2018, For 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 carrybackthree and rejectingsix months ended June 30, 2019, the Company’s refund claim. As a result,effective tax rate was also impacted by the non-deductible Chevron Merger Termination Fee.
In 2018, the Company filed a petition with the U.S. Tax Court to dispute theIRS 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 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 benefit previously recognized in its consolidated financial statementsrelated to the extent necessary to reflectCompany’s 2015 settlement payment for the result of the Tax Court decision. It is reasonably possible the amount of uncertain tax position and/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 currently anticipate a decision to be entered before 2022.
Tronox Advisory Proceeding. For additional information, on income taxes, see Note 10—11—Income Taxesin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
APC 2019 FORM 10-Q | 48 54
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES | |
|
|
| LIQUIDITY AND CAPITAL RESOURCES |
| | | | Three Months Ended | Six Months Ended |
| | March 31, | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
|
| Net cash provided by (used in) operating activities | $ | 1,129 |
| | $ | 1,430 |
| $ | 1,905 |
| | $ | 2,655 |
|
| Net cash provided by (used in) investing activities | (1,528 | ) | | (1,113 | ) | (2,785 | ) | | (3,056 | ) |
| Net cash provided by (used in) financing activities | 1,129 |
| | (1,507 | ) | 980 |
| | (1,826 | ) |
The Company has a variety of funding sources available, including cash, an asset portfolio that provides ongoing cash-flow-generating capacity, and the Company’s credit facility.
During the threesix months ended March 31,June 30, 2019, Anadarko retired $900 million of debt. Anadarko had $2.0$1.4 billion of cash at March 31,June 30, 2019 and 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 and future operating cash flows will be sufficient to fund the Company’s operational and capital programs and its quarterly dividends. The Company continuously monitors its liquidity position and evaluates available funding alternatives in light of current and expected conditions.
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-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 operations and interest payments related to the Company’s outstanding debt.
Cash flows from operating activities were $1.1$1.9 billion for the threesix months ended March 31,June 30, 2019, $301$750 million lower compared to the same period in 2018, primarily due to lower oil and NGL sales revenues resulting from lower prices as well as higher operating costs.the payment of the Chevron Merger Termination Fee of $1.0 billion in 2019. See Note 1—Summary of Significant Accounting Policiesin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information related to the Chevron Merger Termination Fee.
49 55 | APC 2019 FORM 10-Q
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES | |
Capital ExpendituresThe following presents the Company’s capital expenditures:
| | | | Three Months Ended | Six Months Ended |
| | March 31, | June 30, |
| millions | 2019 |
| | 2018 |
| 2019 |
| | 2018 |
|
| Cash Flows from Investing Activities | | | | | | |
Additions to properties and equipment (1) | $ | 1,389 |
| | $ | 1,547 |
| $ | 2,691 |
| | $ | 3,277 |
|
| Adjustments for capital expenditures | | | | | | |
| Changes in capital accruals | (42 | ) | | 142 |
| (74 | ) | | 211 |
|
| Other | (51 | ) | | 15 |
| (64 | ) | | 14 |
|
| Total capital expenditures | $ | 1,296 |
| | $ | 1,704 |
| $ | 2,553 |
| | $ | 3,502 |
|
| | | | | | | |
| Exploration and Production and other capital expenditures | $ | 981 |
| | $ | 1,116 |
| $ | 1,982 |
| | $ | 2,374 |
|
WES Midstream capital expenditures (2) | 315 |
| | 588 |
| 571 |
| | 1,128 |
|
| |
(1) | Additions 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) | WES Midstream includes $49 million at March 31,June 30, 2019, and $260$500 million at March 31,June 30, 2018, of capitalized costs incurred by Anadarko prior to the contribution and sale of midstream assets to WES. |
The Company’s capital expenditures decreased by $408$949 million for the threesix months ended March 31,June 30, 2019. Exploration and Production capital expenditures decreased primarily due to lower development costs of $120$279 million driven by decreasedreduced drilling activitiesactivity in the DJ and Delaware basins and the Gulf of Mexico. Exploration costs decreased by $122 million primarily related to decreased exploration activity in the U.S. onshore. WES Midstream capital expenditures decreased by $273$557 million primarily due to reduced development activity in the Delaware basin following the completion of significant infrastructure projects in 2018.
Investments During the threesix months ended March 31,June 30, 2019, the Company made capital contributions of $130$171 million for equity investments, 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 Red Bluff and Cactus II pipelines in West Texas.
APC 2019 FORM 10-Q | 50 56
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES | |
| | | millions except percentages | March 31, 2019 | | December 31, 2018 | | June 30, 2019 | | December 31, 2018 | |
| Anadarko | | $ | 10,716 |
| | $ | 11,602 |
| | $ | 10,740 |
| | $ | 11,602 |
|
| WES | | 7,208 |
| | 4,815 |
| | 7,489 |
| | 4,815 |
|
| Total debt | | $ | 17,924 |
| | $ | 16,417 |
| | $ | 18,229 |
| | $ | 16,417 |
|
| Total equity | | 10,533 |
| | 10,943 |
| | 9,331 |
| | 10,943 |
|
| Consolidated debt to total capitalization ratio | | 63.0 | % | | 60.0 | % | | 66.1 | % | | 60.0 | % |
Debt-Reduction Program The Company commenced a $2.0 billion debt-reduction program in 2018. During the threesix months ended March 31,June 30, 2019, Anadarko retired $900 million of debt, bringing total repayments under the debt-reduction program to $1.5 billion. No additional debt retirements are anticipated pursuant to the terms of the ChevronOccidental Merger Agreement.
Credit Facilities
APC RCFs The Company has a $3.0 billion senior unsecured RCF that matures in January 2023. The Company’s $2.0 billion 364-day senior unsecured RCF expired in January 2019. At March 31,June 30, 2019, Anadarko had no outstanding borrowings under the APC RCF and was in compliance with all covenants.
WES RCFs Effective on February 15, 2019, WES amended the maturity date of its senior unsecured RCF from February 2023 to February 2024, and upon completion of the WES Merger, expanded the borrowing capacity from $1.5 billion to $2.0 billion (WES RCF). At March 31,June 30, 2019, WES had outstanding borrowings under its RCF of $640$920 million at an interest rate of 3.79%3.71%, outstanding letters of credit of $5 million, available borrowing capacity of $1.4$1.1 billion, and was in compliance with all covenants.
In February 2019, WES borrowed $2.0 billion under its 364-day senior unsecured credit facility (WES 364-DayTerm Loan Facility) 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. TheAs of June 30, 2019, the WES 364-DayTerm Loan Facility willwas anticipated to mature on February 27, 2020, the day prior to the one-year anniversary of the completion of the WES Merger. NetAs of June 30, 2019, net cash proceeds received from future asset sales and debt or equity offerings by WES mustwere required to be used to repay amounts outstanding under the WES 364-DayTerm Loan Facility. At March 31,June 30, 2019, WES had outstanding borrowings under its WES 364-DayTerm Loan Facility of $2.0 billion at an interest rate of 3.87%3.78% and was in compliance with all covenants.
On July 1, 2019, WES intendsentered into an amendment to refinance the obligationsWES Term Loan Facility to, among other things, (i) increase the commitments available under the 364-DayWES Term Loan Facility priorfrom $2.0 billion to its$3.0 billion, the incremental $1.0 billion of which may be drawn by WES on or before September 30, 2019, (ii) extend the maturity indate from February 2020. 27, 2020 to December 31, 2020, and (iii) modify the provision requiring that all debt issuance proceeds be used to repay the WES Term Loan Facility to allow for a $1.0 billion carve out of debt offering proceeds.
WGP RCF In March 2019, the $35 million senior secured RCF (WGP RCF) matured following the completion of the WES Merger. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information related to the WES Merger.
51 57 | APC 2019 FORM 10-Q
|
| | |
| MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES | |
Debt Activity Amounts in the table below do not include finance lease activity and are presented at face value.
|
| | | | | |
| | Three Months Ended |
| | |
millions | Company | March 31, 2019 |
| | Description |
Borrowings | WES | 2,000 |
| | WES 364-Day Facility (1)
|
| WES | 420 |
| | WES RCF (2)
|
Repayments | Anadarko | (600 | ) | | 8.700% Senior Notes due 2019 |
| Anadarko | (300 | ) | | 6.950% Senior Notes due 2019 |
| WES | (28 | ) | | WGP RCF |
|
| | | | | | |
| | | Six Months Ended |
| | |
| millions | Company | June 30, 2019 |
| | Description |
| Borrowings | WES | $ | 2,000 |
| | WES Term Loan Facility (1) |
| | WES | 700 |
| | WES RCF (2) |
| Repayments | Anadarko | (600 | ) | | 8.700% Senior Notes due 2019 |
| | Anadarko | (300 | ) | | 6.950% Senior Notes due 2019 |
| | WES | (28 | ) | | WGP RCF |
| |
(1) | Borrowings were used to fund substantially all of the cash portion of the consideration for the WES midstream asset contribution and sale and the payment of related transaction costs. |
| |
(2) | Borrowings were used for general partnership purposes, including capital expenditures. |
See Note 8—9—Debtin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information on the Company’s debt instruments.
Debt MaturitiesAnadarko’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, will be $942 million at the next put date in October 2019. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31,June 30, 2019, as the Company has the ability and intent to refinance these obligations using long-term debt, should a put be exercised.
For additional information on the Company’s debt instruments, see Note 8—9—Debt in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Derivative InstrumentsFor information on derivative instruments, including cash flow treatment, see Note 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Common Stock DividendsAnadarko paid dividends to its common stockholders of $150$299 million during the threesix months ended March 31,June 30, 2019, and $127$254 million during the threesix months ended March 31,June 30, 2018. In February 2018, the Company increased the quarterly dividend to $0.25 per share. As part of the Company’s focus on increasing shareholderstockholder returns, the quarterly dividend 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 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.
Distributions to Noncontrolling Interest OwnersDistributions to noncontrolling interest owners primarily relate to WES distributions to third parties of $130$255 million for the threesix months ended March 31,June 30, 2019, and $118$238 million for the threesix months ended March 31,June 30, 2018.
|
|
| RECENT ACCOUNTING DEVELOPMENTS |
APC 2019 FORM 10-Q | 52 58
|
| | |
| MARKET RISK
QUANTITATIVE AND QUALITATIVE DISCLOSURES | |
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. 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 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
The Company’s most significant market risk relates to prices for oil, natural gas, 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.
Derivative Instruments Held for Non-Trading PurposesThe Company had derivative instruments in place to reduce the price risk associated with future production of 2416 MMBbls of oil at March 31,June 30, 2019, with a net derivative asset position of $16$21 million. Based on actual derivative contractual volume, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $51$30 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $50$36 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.
Borrowings, if any, under each of the APC RCF, the WES RCF, and the WES 364-DayTerm Loan Facility are subject to variable interest rates. The remaining balance of the Anadarko’s short-term and long-term borrowings has fixed interest rates. The Company has $2.9 billion of LIBOR-based obligations that are presented on the Company’s Consolidated Balance Sheets net of preferred investments in two noncontrolled 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 the 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 March 31,June 30, 2019, the Company had a net derivative liability position of $1.3$1.6 billion related to interest-rate swaps. A 10% increase (decrease) in the LIBOR interest-rate curve would decrease (increase) the aggregate fair value of outstanding interest-rate swap agreements by $117$105 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 7—8—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
53 59 | APC 2019 FORM 10-Q
Item 4. Controls and Procedures
|
|
| EVALUATION AND DISCLOSURE CONTROLS AND PROCEDURES |
Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of March 31,June 30, 2019.
|
|
| CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING |
There were no changes in Anadarko’s internal control over financial reporting during the firstsecond quarter of 2019 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
APC 2019 FORM 10-Q | 54 60
Item 1. 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 U.S. Environmental Protection Agency (EPA) and the State of Wyoming 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 April 2019, Kerr-McGee Oil and Gas Onshore, LP, a subsidiary of the Company, is currently in negotiationsentered into a Compliance Order on Consent 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 predictRegulations at certain facilities in the outcomeDJ basin in Colorado and agreed to pay a penalty of settlement discussions, it is likely a resolution of this matter will result in a fine or penalty in excess of $100,000.$521,400.
Kerr-McGee Gathering, LLC, a subsidiary of the Company, is currently in negotiations with the EPA and the DepartmentState of JusticeColorado 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 11—13—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for a discussion of material legal proceedings to which the Company is a party.
55 61 | APC 2019 FORM 10-Q
Item 1A. Risk Factors
Due to the Company’s proposed combination with Chevron,Occidental, there have been material changes to the risk factors included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.
For a complete discussion of the Company’s risk factors, refer to the risk factors included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 and the following risk factors relating to the proposed combination with Chevron:Occidental:
We will be subject to business uncertainties while the ChevronOccidental Merger is pending, which could adversely affect our businesses.
Uncertainty about the effect of the ChevronOccidental Merger on employees and those that do business with us may have an adverse effect on Anadarko. These uncertainties may impair our ability to attract, retain and motivate key personnel until the ChevronOccidental Merger is completed and for a period of time thereafter, and could cause those that deal with us to delay or defer certain business decisions or seek to terminate, change or renegotiate their existing business relationships with us. Employee retention at Anadarko may be challenging during the pendency of the ChevronOccidental Merger, as employees may experience uncertainty about their future roles. In addition, the ChevronOccidental Merger Agreement restricts us from entering into certain corporate transactions, entering into certain material contracts, making certain changes to our capital budget, incurring certain indebtedness and taking other specified actions without the consent of Chevron,Occidental, and generally requires us to continue our operations in the ordinary course of business during the pendency of the ChevronOccidental Merger. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the ChevronOccidental Merger.
We may be subject to lawsuits relating to the ChevronOccidental Merger, which could adversely affect our business, financial condition and operating results.
Anadarko Chevron and/or their respectiveits directors and officers may be subject to lawsuits relating to the ChevronOccidental Merger. Such litigation is very common in connection with acquisitions of public companies, regardless of any merits related to the underlying acquisition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results.
Completion of the ChevronOccidental Merger is subject to a number of conditions, and if these conditions are not satisfied or waived, the ChevronOccidental Merger will not be completed. Failure to complete, or significant delays in completing, the ChevronOccidental Merger could negatively affect the trading pricesprice of our common stock and our future business and financial results.
Completion of the ChevronOccidental Merger is subject to satisfaction or waiver of certain closing conditions, including (1) the adoption of the Chevron OccidentalMerger Agreement by Anadarko stockholders, (2) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, as amended, applicable to the Chevron OccidentalMerger (the U.S. Federal Trade Commission granted early termination of the applicable waiting period on June 3, 2019), (3) the absence of any order or law prohibiting consummation of the ChevronOccidental Merger, (4) the effectiveness of the Registration Statement on Form S-4 to be(the Registration Statement) filed by ChevronOccidental pursuant to which the shares of ChevronOccidental common stock to be issued in connection with the ChevronOccidental Merger will be registered with the Securities and Exchange Commission (the Registration Statement was declared effective on July 11, 2019) and (5) the authorization for listing on the New York Stock ExchangeNYSE of the shares of ChevronOccidental common stock to be issued in connection with the ChevronOccidental Merger. There can be no assurance that the conditions to the completion of the ChevronOccidental Merger will be satisfied or waived or that the ChevronOccidental Merger will be completed.
If the ChevronOccidental Merger is not completed, or if there are significant delays in completing the ChevronOccidental Merger, the trading pricesprice of our common stock and our future business and financial results could be negatively affected, and we may be subject to several risks, including the following:
| |
| – | the requirement that weto, under certain circumstances provided in the Occidental Merger Agreement, pay ChevronOccidental a termination fee of $1.0 billion, under certain circumstances provided in the Chevron Merger Agreement;which would have otherwise been available for general corporate purposes and other uses; |
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| – | negative reactions from the financial markets, including declines in the prices of our common stock due to the fact that the current pricesprice may reflect a market assumption that the ChevronOccidental Merger will be completed; |
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| – | having to pay certain significanttransaction expenses and other costs relating to the ChevronOccidental Merger; and |
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| – | the attention of our management willmay have been diverted to the ChevronOccidental Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us. |
APC 2019 FORM 10-Q | 56 62
The ChevronOccidental Merger Agreement limits our ability to pursue alternatives to the ChevronOccidental Merger.
The ChevronOccidental Merger Agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our stockholders than the ChevronOccidental Merger, or may result in a potential competing acquirer of the Company proposing to pay a lower per share price to acquire us than it might otherwise have proposed to pay. These provisions include a general prohibition on us from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our Board, entering into discussions with any third party regarding any competing proposal or offer for a competing transaction.
Because the exchange ratio in the ChevronOccidental Merger Agreement is fixed and because the market price of ChevronOccidental common stock will fluctuate prior to the completion of the ChevronOccidental Merger, our stockholders cannot be sure of the market value of the ChevronOccidental common stock they will receive as consideration in the ChevronOccidental Merger.
Under the terms of the ChevronOccidental Merger Agreement, our stockholders will receive consideration consisting of a combination of 0.3869$59.00 in cash and 0.2934 of a share of ChevronOccidental common stock and $16.25 of cash for each share of Anadarko common stock. Based on the closing price of Chevron common stock on April 11, 2019, the last trading day prior to the announcement of the Chevron Merger, the merger consideration was valued at $65.00 per share. The exchange ratio for the stock component of the merger consideration is fixed, and theresubject to adjustment only in limited circumstances pursuant to the Occidental Merger Agreement. There will be no adjustment to the merger consideration forexchange ratio to reflect changes in the market price of Chevroneither Occidental common stock or our common stock prior tobetween the date the Occidental Merger Agreement was signed and completion of the Occidental Merger.
Accordingly, the actual value of the stock component of any merger consideration received by our stockholders at the completion of the Chevron Merger.
IfOccidental Merger will depend on the Chevron Merger is completed, there will be amarket value of Occidental common stock at that time. This market value may differ, possibly materially, from the market value of Occidental common stock at the time lapse between the date of signing of the ChevronOccidental Merger Agreement and the date on which our stockholders who are entitled to receive the merger consideration actually receive the merger consideration.was signed or at any other time. The respective market valuesprices of Chevron common stockshares of Occidental and ourAnadarko common stock have fluctuated since the Occidental Merger Agreement was executed and maywill continue to fluctuate during this periodthrough the completion of the Occidental Merger as a result of a variety of factors, including general market and economic conditions, changes in each company’s business, operations and prospects, commodity prices, regulatory considerations, and the market’s assessment of Chevron’sOccidental’s business and the ChevronOccidental Merger. Such factors are difficult to predict and in many cases may be beyond the control of ChevronOccidental and us.
Material differences between the estimated and actual timing of critical events may affect the completion, cost and commencement of production from development projects.
We are involved in certain large development projects, such as the Mozambique LNG project for which the Company announced FID in June 2019. The completion of such projects may be delayed beyond our anticipated completion dates. Key factors that may affect the timing and outcome of such projects include the following:
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| – | project approvals and funding by joint-venture partners |
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| – | availability of project financing |
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| – | timely issuance of permits and licenses by governmental agencies or legislative and other governmental approvals |
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| – | availability of qualified personnel |
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| – | civil and political environment of, and existing infrastructure in, the country or region in which the project is located |
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| – | manufacturing and delivery schedules of critical equipment |
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| – | commercial arrangements for pipelines, tankers, and related equipment to transport and market hydrocarbons |
Delays and differences between estimated and actual valuetiming of critical events or our ability to secure financing on acceptable terms or at all may affect the stock componentforward-looking statements related to large development projects. If we are unable to complete such projects at their expected costs and in a timely manner, our financial condition, results of operations, or cash flows could be materially and adversely affected.
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:
| |
| – | the validity of our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses, and costs |
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| – | the assumption of environmental, decommissioning, and other liabilities, and losses or costs for which we are not indemnified or for which our indemnity is inadequate |
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| – | a failure to 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:
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| – | possible delays in closing |
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| – | lower-than-expected sales proceeds for the disposed assets |
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| – | 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 merger consideration received by our stockholders at the completion of the Chevron Merger will depend on the market value of Chevron common stock at that time. This market valuesuch retained liability or indemnification obligation may differ, possibly materially, from the market value of Chevron common stockbe difficult to quantify at the time the Chevron Merger Agreement was entered into or at any other time.
We may terminate the Chevron Merger Agreement in order to enter into a definitive merger agreement with Occidental.
On May 6, 2019, we announced that our Board has determined that the Occidental Proposal constitutes a “Superior Proposal” as defined in the Chevron Merger Agreement and that, after complying with its obligations to Chevron under the Chevron Merger Agreement, the Company intends to terminate the Chevron Merger Agreement in order to enter into a definitive merger agreement with Occidental in connection with the Occidental Proposal. Pursuant to the Chevron Merger Agreement, Chevron has the right, during the four business day period ending on May 10, 2019, which may be extended in accordance with the terms of the Chevron Merger Agreement, to propose revisions to the terms of the Chevron Merger Agreement, or to make another proposal. The Company is required to, and will, make its representatives reasonably available to negotiate with Chevron during this period with respect to such proposed revisions or other proposal, if any. If the Company terminates the Chevron Merger Agreement in order to enter into a definitive agreement with respect to the Occidental Proposal, the Company will pay Chevron a $1.0 billion termination fee as required by the Chevron Merger Agreement. However, there can be no assurance that a definitive agreement between the Company and Occidental will be executed or that a transaction between the Company and Occidental will be consummated. The Chevron Merger Agreement remains in effect unless and until terminated, and accordingly, our Board reaffirms its existing recommendation of the transaction with Chevron at this time.
The risk factors set forth above regardingand ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the Chevron Merger would apply correlativelyCompany from guarantees or other credit support provided prior to the merger transaction with Occidentalsale 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. For example, Sanchez Energy Corporation, which purchased substantially all of Anadarko’s Eagleford oil and natural-gas assets in 2017, recently elected to defer making an interest payment on its 6.125% Senior Notes due 2023. The indenture governing the 6.125% Senior Notes provides for a 30-day grace period, which expires on August 14, 2019, to make the scheduled interest payment. Anadarko is currently evaluating the matter. 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 terminatesmay remain secondarily liable for the Chevron Merger Agreement and enters into a definitive agreement with respectobligations guaranteed or supported to the Occidental Proposal.extent that the buyer of the assets fails to perform these obligations, which could also result in impairments to the associated assets retained by the Company.
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.
57 | APC 2019 FORM 10-Q | 64
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following sets forth information with respect to repurchases made by the Company of its shares of common stock during the firstsecond quarter of 2019:
|
| | | | | | | | | | | | |
| 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) | |
| January 1 - 31, 2019 | 24,942 |
| | $ | 48.39 |
| — |
| | $ | 1,250,000,064 |
|
| February 1 - 28, 2019 | 2,299 |
| | $ | 43.67 |
| — |
| | $ | 1,250,000,064 |
|
| March 1 - 31, 2019 | 344,288 |
| | $ | 44.62 |
| — |
| | $ | 1,250,000,064 |
|
| Total | 371,529 |
| | $ | 44.87 |
| — |
| |
|
|
|
| | | | | | | | | | | | |
| 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) | |
| April 1 - 30, 2019 | 164,077 |
| | $ | 61.07 |
| — |
| | $ | 1,250,000,064 |
|
| May 1 - 31, 2019 | 4,298 |
| | $ | 73.08 |
| — |
| | $ | 1,250,000,064 |
|
| June 1 - 30, 2019 | 8,825 |
| | $ | 70.40 |
| — |
| | $ | 1,250,000,064 |
|
| Total | 177,200 |
| | $ | 61.83 |
| — |
| |
|
|
| |
(1) | During the firstsecond quarter of 2019, 372177 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. |
| |
(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. No additional share repurchases are anticipated pursuant to the terms of the ChevronOccidental Merger Agreement. For additional information, see Note 13—15—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10‑Q. |
65 | APC 2019 FORM 10-Q | 58
|
| | |
| OTHER INFORMATION
| Table of Contents
|
Item 6. Exhibits
Exhibits designated by an asterisk (*) are filed herewith orherewith; exhibits designated by a double asterisk (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing under File Number 1-8968 as indicated.
|
| | | | |
| Exhibit Number | | Description |
| † | 2 | (i) | | |
| † | 2 | (ii) | | |
| | 3 | (i) | | |
| | | (ii) | | |
| * | 10 | (i) | | |
| * | | (ii) | | |
| * |
| (iii) | | |
| * | | (iv) | | |
| * | 31 | (i) | | |
| * | 31 | (ii) | | |
| ** | 32 | | | |
* | 101 | .INS | | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
| * | 101 | .SCH | | XBRL Schema Document |
| * | 101 | .CAL | | XBRL Calculation Linkbase Document |
| * | 101 | .DEF | | XBRL Definition Linkbase Document |
| * | 101 | .LAB | | XBRL Label Linkbase Document |
| * | 101 | .PRE | | XBRL Presentation Linkbase Document |
| |
| † | Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request |
59 | APC 2019 FORM 10-Q | 66
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | |
| | | ANADARKO PETROLEUM CORPORATION |
| | | (Registrant) | |
| | | |
May 8,July 30, 2019 | By: | /s/ BENJAMIN M. FINK |
| | | Benjamin M. Fink Executive Vice President, Finance and Chief Financial Officer |
67 | APC 2019 FORM 10-Q | 60
