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Form 10-Q
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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WPX Energy, Inc.
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(Exact Name of Registrant as Specified in Its Charter)
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Delaware
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45-1836028
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(State or Other Jurisdiction of Incorporation or Organization)
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(IRS Employer Identification No.)
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3500 One Williams Center,
Tulsa, Oklahoma
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74172-0172
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(Address of Principal Executive Offices)
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(Zip Code)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, $0.01 par value
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New York Stock Exchange
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6.25% Series A Mandatory Convertible Preferred Stock, $0.01 par value
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act: None
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Large accelerated filer
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þ
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Accelerated filer
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¨
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Non-accelerated filer
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¨
(Do not check if a smaller reporting company)
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Smaller reporting company
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¨
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Emerging growth company
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¨
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Page
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Part I.
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Financial Information
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Item 1.
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Financial Statements (Unaudited)
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Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016
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Consolidated Statements of Operations for the three and six months ended June 30, 2017 and 2016
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Consolidated Statements of Changes in Equity for the six months ended June 30, 2017
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Consolidated Statements of Cash Flows for the six months ended June 30, 2017 and 2016
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Item 2.
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Item 3.
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Item 4.
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Part II.
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Other Information
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Item 1.
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Item 1A.
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Item 2.
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Item 3.
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Item 4.
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Item 5.
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Item 6.
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•
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amounts and nature of future capital expenditures;
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•
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crude oil, natural gas and NGL prices and demand;
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•
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expansion and growth of our business and operations;
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•
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financial condition and liquidity;
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•
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business strategy;
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•
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estimates of proved oil and natural gas reserves;
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•
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reserve potential;
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•
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development drilling potential;
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•
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cash flow from operations or results of operations;
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•
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acquisitions or divestitures; and
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•
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seasonality of our business.
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•
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availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future oil and natural gas reserves), market demand, volatility of prices and the availability and cost of capital;
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•
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inflation, interest rates, fluctuation in foreign exchange and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
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•
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the strength and financial resources of our competitors;
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•
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development of alternative energy sources;
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•
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the impact of operational and development hazards;
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•
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costs of, changes in, or the results of laws, government regulations (including climate change regulation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;
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•
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changes in maintenance and construction costs;
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•
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changes in the current geopolitical situation;
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•
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our exposure to the credit risk of our customers;
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•
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risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;
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•
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risks associated with future weather conditions;
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•
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acts of terrorism;
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•
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other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”; and
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•
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additional risks described in our filings with the Securities and Exchange Commission (“SEC”).
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June 30,
2017 |
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December 31,
2016 |
||||
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(Millions)
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||||||
Assets
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|
|
|
||||
Current assets:
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|
|
|
||||
Cash and cash equivalents
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$
|
8
|
|
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$
|
496
|
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Accounts receivable, net of allowance of $1 million as of June 30, 2017 and $3 million as of December 31, 2016
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205
|
|
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168
|
|
||
Derivative assets
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110
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|
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26
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Inventories
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41
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|
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36
|
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Other
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29
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|
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28
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Total current assets
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393
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|
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754
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Properties and equipment (successful efforts method of accounting)
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10,244
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8,929
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Less—accumulated depreciation, depletion and amortization
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(2,759
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)
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(2,455
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)
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||
Properties and equipment, net
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7,485
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6,474
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Derivative assets
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58
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12
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Other noncurrent assets
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26
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24
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Total assets
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$
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7,962
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$
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7,264
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||||
Liabilities and Equity
|
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Current liabilities:
|
|
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||||
Accounts payable
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$
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348
|
|
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$
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222
|
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Accrued and other current liabilities
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244
|
|
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303
|
|
||
Derivative liabilities
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27
|
|
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152
|
|
||
Total current liabilities
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619
|
|
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677
|
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Deferred income taxes
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226
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|
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251
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Long-term debt, net
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2,601
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2,575
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Derivative liabilities
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8
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|
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63
|
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Asset retirement obligations
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98
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|
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100
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Other noncurrent liabilities
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106
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132
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Contingent liabilities and commitments (Note 9)
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Equity:
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Stockholders’ equity:
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||||
Preferred stock (100 million shares authorized at $0.01 par value; 4.8 million shares outstanding at June 30, 2017 and December 31, 2016)
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232
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232
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Common stock (2 billion shares authorized at $0.01 par value; 398.0 million and 344.7 million shares issued and outstanding at June 30, 2017 and December 31, 2016)
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4
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3
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Additional paid-in-capital
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7,472
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6,803
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Accumulated deficit
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(3,404
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)
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(3,572
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)
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Total stockholders’ equity
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4,304
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3,466
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Total liabilities and equity
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$
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7,962
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$
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7,264
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Three months
ended June 30, |
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Six months
ended June 30, |
||||||||||||
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2017
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2016
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2017
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2016
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||||||||
Revenues:
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(Millions, except per-share amounts)
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||||||||||||||
Product revenues:
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||||||||
Oil sales
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$
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226
|
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$
|
142
|
|
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$
|
414
|
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$
|
239
|
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Natural gas sales
|
40
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|
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24
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|
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84
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|
|
49
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||||
Natural gas liquid sales
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23
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10
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|
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44
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|
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15
|
|
||||
Total product revenues
|
289
|
|
|
176
|
|
|
542
|
|
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303
|
|
||||
Net gain (loss) on derivatives
|
116
|
|
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(154
|
)
|
|
319
|
|
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(97
|
)
|
||||
Gas management
|
8
|
|
|
116
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|
|
13
|
|
|
147
|
|
||||
Other
|
—
|
|
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—
|
|
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—
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|
|
1
|
|
||||
Total revenues
|
413
|
|
|
138
|
|
|
874
|
|
|
354
|
|
||||
Costs and expenses:
|
|
|
|
|
|
|
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||||||||
Depreciation, depletion and amortization
|
171
|
|
|
163
|
|
|
318
|
|
|
315
|
|
||||
Lease and facility operating
|
53
|
|
|
41
|
|
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101
|
|
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83
|
|
||||
Gathering, processing and transportation
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21
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|
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20
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42
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|
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36
|
|
||||
Taxes other than income
|
23
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|
|
16
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|
|
42
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|
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27
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|
||||
Exploration (Note 5)
|
21
|
|
|
12
|
|
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60
|
|
|
21
|
|
||||
General and administrative (including equity-based compensation of $9 million, $9 million, $16 million and $15 million for the respective periods)
|
46
|
|
|
55
|
|
|
89
|
|
|
108
|
|
||||
Gas management
|
8
|
|
|
132
|
|
|
13
|
|
|
171
|
|
||||
Net gain on sales of assets (Note 5)
|
(7
|
)
|
|
(4
|
)
|
|
(42
|
)
|
|
(202
|
)
|
||||
Other—net
|
8
|
|
|
2
|
|
|
12
|
|
|
4
|
|
||||
Total costs and expenses
|
344
|
|
|
437
|
|
|
635
|
|
|
563
|
|
||||
Operating income (loss)
|
69
|
|
|
(299
|
)
|
|
239
|
|
|
(209
|
)
|
||||
Interest expense
|
(46
|
)
|
|
(53
|
)
|
|
(93
|
)
|
|
(110
|
)
|
||||
Investment income and other
|
—
|
|
|
(1
|
)
|
|
2
|
|
|
1
|
|
||||
Income (loss) from continuing operations before income taxes
|
23
|
|
|
(353
|
)
|
|
148
|
|
|
(318
|
)
|
||||
Provision (benefit) for income taxes
|
(53
|
)
|
|
(130
|
)
|
|
(22
|
)
|
|
(95
|
)
|
||||
Income (loss) from continuing operations
|
76
|
|
|
(223
|
)
|
|
170
|
|
|
(223
|
)
|
||||
Income (loss) from discontinued operations
|
—
|
|
|
25
|
|
|
(2
|
)
|
|
13
|
|
||||
Net income (loss)
|
76
|
|
|
(198
|
)
|
|
168
|
|
|
(210
|
)
|
||||
Less: Dividends on preferred stock
|
4
|
|
|
6
|
|
|
8
|
|
|
11
|
|
||||
Net income (loss) available to WPX Energy, Inc. common stockholders
|
$
|
72
|
|
|
$
|
(204
|
)
|
|
$
|
160
|
|
|
$
|
(221
|
)
|
Amounts available to WPX Energy, Inc. common stockholders:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
72
|
|
|
$
|
(229
|
)
|
|
$
|
162
|
|
|
$
|
(234
|
)
|
Income (loss) from discontinued operations
|
—
|
|
|
25
|
|
|
(2
|
)
|
|
13
|
|
||||
Net income (loss)
|
$
|
72
|
|
|
$
|
(204
|
)
|
|
$
|
160
|
|
|
$
|
(221
|
)
|
Basic earnings (loss) per common share:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
0.18
|
|
|
$
|
(0.76
|
)
|
|
$
|
0.41
|
|
|
$
|
(0.81
|
)
|
Income (loss) from discontinued operations
|
—
|
|
|
0.08
|
|
|
—
|
|
|
0.04
|
|
||||
Net income (loss)
|
$
|
0.18
|
|
|
$
|
(0.68
|
)
|
|
$
|
0.41
|
|
|
$
|
(0.77
|
)
|
Basic weighted-average shares
|
397.8
|
|
|
300.7
|
|
|
392.1
|
|
|
288.2
|
|
||||
Diluted earnings (loss) per common share:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
0.18
|
|
|
$
|
(0.76
|
)
|
|
$
|
0.40
|
|
|
$
|
(0.81
|
)
|
Income (loss) from discontinued operations
|
—
|
|
|
0.08
|
|
|
—
|
|
|
0.04
|
|
||||
Net income (loss)
|
$
|
0.18
|
|
|
$
|
(0.68
|
)
|
|
$
|
0.40
|
|
|
$
|
(0.77
|
)
|
Diluted weighted-average shares
|
423.2
|
|
|
300.7
|
|
|
418.8
|
|
|
288.2
|
|
|
WPX Energy, Inc., Stockholders
|
||||||||||||||||||
|
Preferred Stock
|
|
Common
Stock
|
|
Additional
Paid-In-
Capital
|
|
Accumulated
Deficit
|
|
Total
Stockholders’
Equity
|
||||||||||
|
|
|
|
||||||||||||||||
Balance at December 31, 2016
|
$
|
232
|
|
|
$
|
3
|
|
|
$
|
6,803
|
|
|
$
|
(3,572
|
)
|
|
$
|
3,466
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
168
|
|
|
168
|
|
|||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
8
|
|
|||||
Issuance of common stock to public, net of offering costs
|
—
|
|
|
1
|
|
|
669
|
|
|
—
|
|
|
670
|
|
|||||
Dividends on preferred stock
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
(8
|
)
|
|||||
Balance at June 30, 2017
|
$
|
232
|
|
|
$
|
4
|
|
|
$
|
7,472
|
|
|
$
|
(3,404
|
)
|
|
$
|
4,304
|
|
|
Six months
ended June 30, |
||||||
|
2017
|
|
2016
|
||||
Operating Activities(a)
|
(Millions)
|
||||||
Net income (loss)
|
$
|
168
|
|
|
$
|
(210
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
||||
Depreciation, depletion and amortization
|
318
|
|
|
324
|
|
||
Deferred income tax provision (benefit)
|
(24
|
)
|
|
(82
|
)
|
||
Provision for impairment of properties and equipment (including certain exploration expenses)
|
58
|
|
|
19
|
|
||
Net (gain) loss on derivatives in continuing operations
|
(319
|
)
|
|
97
|
|
||
Net settlements related to derivatives in continuing operations
|
9
|
|
|
202
|
|
||
Net loss on derivatives included in discontinued operations
|
—
|
|
|
46
|
|
||
Amortization of stock-based awards
|
17
|
|
|
17
|
|
||
Net gain on sales of assets
|
(41
|
)
|
|
(254
|
)
|
||
Cash provided (used) by operating assets and liabilities:
|
|
|
|
||||
Accounts receivable
|
(49
|
)
|
|
102
|
|
||
Inventories
|
(3
|
)
|
|
9
|
|
||
Other current assets
|
(5
|
)
|
|
3
|
|
||
Accounts payable
|
72
|
|
|
(28
|
)
|
||
Federal income taxes receivable (payable)
|
12
|
|
|
(33
|
)
|
||
Accrued and other current liabilities
|
(45
|
)
|
|
(99
|
)
|
||
Payments on liabilities accrued in 2015 for retained transportation and gathering contracts related to discontinued operations
|
(29
|
)
|
|
(30
|
)
|
||
Other, including changes in other noncurrent assets and liabilities
|
3
|
|
|
6
|
|
||
Net cash provided by operating activities(a)
|
142
|
|
|
89
|
|
||
Investing Activities(a)
|
|
|
|
||||
Capital expenditures(b)
|
(542
|
)
|
|
(291
|
)
|
||
Proceeds from sales of assets
|
38
|
|
|
1,139
|
|
||
Purchase of business
|
(798
|
)
|
|
—
|
|
||
Purchase of investment
|
(3
|
)
|
|
—
|
|
||
Other
|
(3
|
)
|
|
(4
|
)
|
||
Net cash provided by (used in) investing activities(a)
|
(1,308
|
)
|
|
844
|
|
||
Financing Activities
|
|
|
|
||||
Proceeds from common stock
|
671
|
|
|
540
|
|
||
Dividends paid on preferred stock
|
(7
|
)
|
|
(11
|
)
|
||
Borrowings on credit facility
|
85
|
|
|
380
|
|
||
Payments on credit facility
|
(60
|
)
|
|
(645
|
)
|
||
Taxes paid for shares withheld
|
(10
|
)
|
|
(4
|
)
|
||
Payments for retirement of long-term debt
|
—
|
|
|
(196
|
)
|
||
Payments for credit facility amendment fees
|
—
|
|
|
(3
|
)
|
||
Other
|
(1
|
)
|
|
(1
|
)
|
||
Net cash provided by financing activities
|
678
|
|
|
60
|
|
||
Net increase (decrease) in cash and cash equivalents
|
(488
|
)
|
|
993
|
|
||
Cash and cash equivalents at beginning of period
|
496
|
|
|
38
|
|
||
Cash and cash equivalents at end of period
|
$
|
8
|
|
|
$
|
1,031
|
|
__________
|
|
|
|
||||
(a) Amounts reflect continuing and discontinued operations unless otherwise noted. See Note 3 of Notes to Consolidated Financial Statements for discussion of discontinued operations.
|
|
|
|
||||
(b) Increase to properties and equipment
|
$
|
(596
|
)
|
|
$
|
(264
|
)
|
Changes in related accounts payable and accounts receivable
|
54
|
|
|
(27
|
)
|
||
Capital expenditures
|
$
|
(542
|
)
|
|
$
|
(291
|
)
|
|
Three months ended June 30, 2016
|
|
Six months ended June 30, 2016
|
||||
|
(Millions)
|
||||||
Total revenues(a)
|
$
|
(4
|
)
|
|
$
|
64
|
|
Costs and expenses:
|
|
|
|
||||
Depreciation, depletion and amortization
|
$
|
—
|
|
|
$
|
9
|
|
Lease and facility operating
|
1
|
|
|
18
|
|
||
Gathering, processing and transportation
|
5
|
|
|
48
|
|
||
Taxes other than income
|
(1
|
)
|
|
1
|
|
||
General and administrative
|
1
|
|
|
8
|
|
||
Other—net
|
2
|
|
|
6
|
|
||
Total costs and expenses
|
8
|
|
|
90
|
|
||
Operating loss
|
(12
|
)
|
|
(26
|
)
|
||
Gain on sale of assets
|
52
|
|
|
52
|
|
||
Income from discontinued operations before income taxes
|
40
|
|
|
26
|
|
||
Income tax provision(b)
|
15
|
|
|
13
|
|
||
Income from discontinued operations
|
$
|
25
|
|
|
$
|
13
|
|
|
Three months
ended June 30, |
|
Six months
ended June 30, |
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
|
(Millions, except per-share amounts)
|
||||||||||||||
Income (loss) from continuing operations
|
$
|
76
|
|
|
$
|
(223
|
)
|
|
$
|
170
|
|
|
$
|
(223
|
)
|
Less: Dividends on preferred stock
|
4
|
|
|
6
|
|
|
8
|
|
|
11
|
|
||||
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic earnings (loss) per common share
|
$
|
72
|
|
|
$
|
(229
|
)
|
|
$
|
162
|
|
|
$
|
(234
|
)
|
Add: Dividends on preferred stock upon assumed conversion of 6.25% Series A mandatory convertible preferred stock
|
4
|
|
|
—
|
|
|
8
|
|
|
—
|
|
||||
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for diluted earnings (loss) per common share
|
$
|
76
|
|
|
$
|
(229
|
)
|
|
$
|
170
|
|
|
$
|
(234
|
)
|
|
|
|
|
|
|
|
|
||||||||
Basic weighted-average shares
|
397.8
|
|
|
300.7
|
|
|
392.1
|
|
|
288.2
|
|
||||
Effect of dilutive securities(a):
|
|
|
|
|
|
|
|
||||||||
Nonvested restricted stock units and awards
|
1.5
|
|
|
—
|
|
|
2.7
|
|
|
—
|
|
||||
Stock options
|
0.1
|
|
|
—
|
|
|
0.2
|
|
|
—
|
|
||||
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock
|
23.8
|
|
|
—
|
|
|
23.8
|
|
|
—
|
|
||||
Diluted weighted-average shares
|
423.2
|
|
|
300.7
|
|
|
418.8
|
|
|
288.2
|
|
||||
Earnings (loss) per common share from continuing operations:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.18
|
|
|
$
|
(0.76
|
)
|
|
$
|
0.41
|
|
|
$
|
(0.81
|
)
|
Diluted
|
$
|
0.18
|
|
|
$
|
(0.76
|
)
|
|
$
|
0.40
|
|
|
$
|
(0.81
|
)
|
|
Three months
ended June 30, |
|
Six months
ended June 30, |
||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||
|
(Millions)
|
||||||||||
Weighted-average nonvested restricted stock units and awards
|
—
|
|
|
1.1
|
|
|
—
|
|
|
1.6
|
|
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock
|
—
|
|
|
34.7
|
|
|
—
|
|
|
34.7
|
|
|
June 30,
|
||||||
|
2017
|
|
2016
|
||||
Options excluded (millions)
|
1.9
|
|
|
2.4
|
|
||
Weighted-average exercise price of options excluded
|
$
|
16.68
|
|
|
$
|
16.46
|
|
Exercise price range of options excluded
|
$11.75 - $21.81
|
|
|
$11.75 - $21.81
|
|
||
Second quarter weighted-average market price
|
$
|
11.40
|
|
|
$
|
9.02
|
|
|
Three months
ended June 30, |
|
Six months
ended June 30, |
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
|
(Millions)
|
||||||||||||||
Unproved leasehold property impairment, amortization and expiration
|
$
|
20
|
|
|
$
|
10
|
|
|
$
|
58
|
|
|
$
|
19
|
|
Geologic and geophysical costs
|
1
|
|
|
1
|
|
|
2
|
|
|
1
|
|
||||
Dry hole costs and impairments of exploratory area well costs
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
Total exploration expenses
|
$
|
21
|
|
|
$
|
12
|
|
|
$
|
60
|
|
|
$
|
21
|
|
|
June 30,
2017 |
|
December 31,
2016 |
||||
|
(Millions)
|
||||||
Material, supplies and other
|
$
|
39
|
|
|
$
|
34
|
|
Crude oil production in transit
|
2
|
|
|
2
|
|
||
Total inventories
|
$
|
41
|
|
|
$
|
36
|
|
|
June 30,
2017 |
|
December 31,
2016 |
||||
|
(Millions)
|
||||||
Credit facility agreement
|
$
|
25
|
|
|
$
|
—
|
|
7.500% Senior Notes due 2020
|
500
|
|
|
500
|
|
||
6.000% Senior Notes due 2022
|
1,100
|
|
|
1,100
|
|
||
8.250% Senior Notes due 2023
|
500
|
|
|
500
|
|
||
5.250% Senior Notes due 2024
|
500
|
|
|
500
|
|
||
Other
|
1
|
|
|
1
|
|
||
Total long-term debt
|
$
|
2,626
|
|
|
$
|
2,601
|
|
Less: Debt issuance costs on long-term debt(a)
|
25
|
|
|
26
|
|
||
Total long-term debt, net(a)
|
$
|
2,601
|
|
|
$
|
2,575
|
|
|
Three months
ended June 30, |
|
Six months
ended June 30, |
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
|
(Millions)
|
||||||||||||||
Current:
|
|
|
|
|
|
|
|
||||||||
Federal
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Deferred:
|
|
|
|
|
|
|
|
||||||||
Federal
|
5
|
|
|
(119
|
)
|
|
51
|
|
|
(119
|
)
|
||||
State
|
(58
|
)
|
|
(11
|
)
|
|
(73
|
)
|
|
24
|
|
||||
|
(53
|
)
|
|
(130
|
)
|
|
(22
|
)
|
|
(95
|
)
|
||||
Total provision (benefit)
|
$
|
(53
|
)
|
|
$
|
(130
|
)
|
|
$
|
(22
|
)
|
|
$
|
(95
|
)
|
|
June 30, 2017
|
|
December 31, 2016
|
||||||||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||
|
(Millions)
|
|
(Millions)
|
||||||||||||||||||||||||||||
Energy derivative assets
|
$
|
—
|
|
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
38
|
|
Energy derivative liabilities
|
$
|
—
|
|
|
$
|
35
|
|
|
$
|
—
|
|
|
$
|
35
|
|
|
$
|
—
|
|
|
$
|
215
|
|
|
$
|
—
|
|
|
$
|
215
|
|
Total debt(a)
|
$
|
—
|
|
|
$
|
2,658
|
|
|
$
|
—
|
|
|
$
|
2,658
|
|
|
$
|
—
|
|
|
$
|
2,702
|
|
|
$
|
—
|
|
|
$
|
2,702
|
|
(a)
|
The carrying value of total debt, excluding capital leases and debt issuance costs, was
$2,625 million
and $2,600 million as of
June 30, 2017
and
December 31, 2016
, respectively. The fair value of our debt, which also excludes capital leases and debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.
|
Commodity
|
|
Period
|
|
Contract Type (a)
|
|
Location
|
|
Notional Volume (b)
|
|
Weighted Average
Price (c) |
|||
|
|
|
|
|
|
|
|
|
|
|
|||
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|||
Crude Oil
|
|
Jul- Dec 2017
|
|
Fixed Price Swaps
|
|
WTI
|
|
(50,750
|
)
|
|
$
|
50.26
|
|
Crude Oil
|
|
Jul - Dec 2017
|
|
Basis Swaps
|
|
Midland-Cushing
|
|
(15,000
|
)
|
|
$
|
(0.60
|
)
|
Crude Oil
|
|
Jul - Dec 2017
|
|
Fixed Price Calls
|
|
WTI
|
|
(4,500
|
)
|
|
$
|
56.47
|
|
Crude Oil
|
|
2018
|
|
Fixed Price Swaps
|
|
WTI
|
|
(50,500
|
)
|
|
$
|
53.16
|
|
Crude Oil
|
|
2018
|
|
Basis Swaps
|
|
Midland-Cushing
|
|
(13,000
|
)
|
|
$
|
(0.94
|
)
|
Crude Oil
|
|
2018
|
|
Fixed Price Calls
|
|
WTI
|
|
(13,000
|
)
|
|
$
|
58.89
|
|
Crude Oil
|
|
2019
|
|
Basis Swaps
|
|
Midland-Cushing
|
|
(7,000
|
)
|
|
$
|
(1.00
|
)
|
Crude Oil
|
|
2020
|
|
Basis Swaps
|
|
Midland-Cushing
|
|
(5,000
|
)
|
|
$
|
(1.16
|
)
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|||
Natural Gas
|
|
Jul-Dec 2017
|
|
Fixed Price Swaps
|
|
Henry Hub
|
|
(170
|
)
|
|
$
|
3.02
|
|
Natural Gas
|
|
Jul-Dec 2017
|
|
Basis Swaps
|
|
Permian
|
|
(73
|
)
|
|
$
|
(0.20
|
)
|
Natural Gas
|
|
Jul-Dec 2017
|
|
Basis Swaps
|
|
San Juan
|
|
(98
|
)
|
|
$
|
(0.18
|
)
|
Natural Gas
|
|
Jul-Dec 2017
|
|
Fixed Price Calls
|
|
Henry Hub
|
|
(16
|
)
|
|
$
|
4.50
|
|
Natural Gas
|
|
2018
|
|
Fixed Price Swaps
|
|
Henry Hub
|
|
(185
|
)
|
|
$
|
2.98
|
|
Natural Gas
|
|
2018
|
|
Basis Swaps
|
|
Permian
|
|
(43
|
)
|
|
$
|
(0.28
|
)
|
Natural Gas
|
|
2018
|
|
Basis Swaps
|
|
San Juan
|
|
(50
|
)
|
|
$
|
(0.34
|
)
|
Natural Gas
|
|
2018
|
|
Basis Swaps
|
|
Waha
|
|
(63
|
)
|
|
$
|
(0.16
|
)
|
Natural Gas
|
|
2018
|
|
Fixed Price Swaptions
|
|
Henry Hub
|
|
(20
|
)
|
|
$
|
3.33
|
|
Natural Gas
|
|
2018
|
|
Fixed Price Calls
|
|
Henry Hub
|
|
(16
|
)
|
|
$
|
4.75
|
|
Natural Gas
|
|
2019
|
|
Basis Swaps
|
|
Permian
|
|
(20
|
)
|
|
$
|
(0.34
|
)
|
Natural Gas
|
|
2019
|
|
Basis Swaps
|
|
Waha
|
|
(80
|
)
|
|
$
|
(0.19
|
)
|
(a)
|
Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with several crude oil and natural gas swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions grant the counterparty the option to enter into future swaps with us.
|
(b)
|
Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.
|
(c)
|
The weighted average price for crude oil is reported in $/Bbl and natural gas is reported in $/MMBtu.
|
|
Gross Amount Presented on Balance Sheet
|
|
Netting Adjustments (a)
|
|
Net Amount
|
||||||
June 30, 2017
|
(Millions)
|
||||||||||
Derivative assets with right of offset or master netting agreements
|
$
|
168
|
|
|
$
|
(33
|
)
|
|
$
|
135
|
|
Derivative liabilities with right of offset or master netting agreements
|
$
|
(35
|
)
|
|
$
|
33
|
|
|
$
|
(2
|
)
|
|
|
|
|
|
|
||||||
December 31, 2016
|
|
|
|
|
|
||||||
Derivative assets with right of offset or master netting agreements
|
$
|
38
|
|
|
$
|
(33
|
)
|
|
$
|
5
|
|
Derivative liabilities with right of offset or master netting agreements
|
$
|
(215
|
)
|
|
$
|
33
|
|
|
$
|
(182
|
)
|
(a)
|
With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
|
|
Three months
ended June 30, |
|
Six months
ended June 30, |
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Production Sales Volume Data(a):
|
|
|
|
|
|
|
|
||||||||
Volumes:
|
|
|
|
|
|
|
|
||||||||
Oil (MBbls)
|
5,331
|
|
|
3,719
|
|
|
9,479
|
|
|
7,493
|
|
||||
Natural gas (MMcf)
|
18,475
|
|
|
18,764
|
|
|
36,080
|
|
|
35,583
|
|
||||
NGLs (MBbls)
|
1,252
|
|
|
909
|
|
|
2,267
|
|
|
1,617
|
|
||||
Combined equivalent volumes (MBoe)(b)
|
9,662
|
|
|
7,755
|
|
|
17,759
|
|
|
15,041
|
|
||||
Per day volumes:
|
|
|
|
|
|
|
|
||||||||
Oil (MBbls/d)
|
58.6
|
|
|
40.9
|
|
|
52.4
|
|
|
41.2
|
|
||||
Natural gas (MMcf/d)
|
203
|
|
|
206
|
|
|
199
|
|
|
196
|
|
||||
NGLs (MBbls/d)
|
13.8
|
|
|
10.0
|
|
|
12.5
|
|
|
8.9
|
|
||||
Per day combined equivalent volumes (MBoe/d)(b)
|
106.2
|
|
|
85.2
|
|
|
98.1
|
|
|
82.6
|
|
||||
Financial Data (millions):
|
|
|
|
|
|
|
|
||||||||
Total product revenues
|
$
|
289
|
|
|
$
|
176
|
|
|
$
|
542
|
|
|
$
|
303
|
|
Total revenues
|
$
|
413
|
|
|
$
|
138
|
|
|
$
|
874
|
|
|
$
|
354
|
|
Operating income (loss)
|
$
|
69
|
|
|
$
|
(299
|
)
|
|
$
|
239
|
|
|
$
|
(209
|
)
|
Capital expenditure activity(c)
|
$
|
317
|
|
|
$
|
94
|
|
|
$
|
596
|
|
|
$
|
264
|
|
(a)
|
Excludes production from discontinued operations.
|
(b)
|
MBoe are converted using the ratio of one barrel of oil, condensate or NGL to six thousand cubic feet of natural gas.
|
(c)
|
Includes capital expenditures activity related to discontinued operations of $2 million and $26 million for the three and six months ended June 30, 2016.
|
•
|
$113 million increase in product revenues, primarily oil sales from $62 million related to higher oil volumes and $22 million related to higher oil prices;
|
•
|
$270 million favorable change in net gain (loss) on derivatives; and
|
•
|
$9 million decrease in general and administrative expenses.
|
•
|
$28 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income; and
|
•
|
$9 million higher exploration costs (see Note 5 of Notes to Consolidated Financial Statements).
|
•
|
$239 million increase in product revenues, primarily oil sales from $111 million related to higher oil prices and $64 million related to higher oil volumes;
|
•
|
$416 million favorable change in net gain (loss) on derivatives; and
|
•
|
$19 million decrease in general and administrative expenses.
|
•
|
$42 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income;
|
•
|
$39 million higher exploration costs (see Note 5 of Notes to Consolidated Financial Statements); and
|
•
|
$42 million
net gain on sales of assets for 2017 compared to
$202 million
net gain on sales of assets for 2016 (see Note 5 of Notes to Consolidated Financial Statements).
|
•
|
continuing to grow our oil production and reserves through the development of our positions in the Delaware Basin, Williston Basin and Gallup Sandstone in the San Juan Basin;
|
•
|
continuing to pursue cost improvements and efficiency gains;
|
•
|
employing new technology and operating methods;
|
•
|
continuing to invest in projects to assess resources and add new development opportunities to our portfolio;
|
•
|
retaining the flexibility to make adjustments to our planned levels and allocation of capital investment expenditures in response to changes in economic conditions or business opportunities; and
|
•
|
continuing to maintain an active economic hedging program around our commodity price risks.
|
•
|
lower than anticipated energy commodity prices;
|
•
|
increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation;
|
•
|
lower than expected results from acquisitions;
|
•
|
higher capital costs of developing our properties, including the impact of inflation;
|
•
|
lower than expected levels of cash flow from operations;
|
•
|
counterparty credit and performance risk;
|
•
|
general economic, financial markets or industry downturn;
|
•
|
unavailability of capital either under our revolver or access to capital markets;
|
•
|
changes in the political and regulatory environments; and
|
•
|
decreased drilling success.
|
|
Three months
ended June 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2017
|
|
2016
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Revenues:
|
|
|
|
|
|
|
|
|||||||
Oil sales
|
$
|
226
|
|
|
$
|
142
|
|
|
$
|
84
|
|
|
59
|
%
|
Natural gas sales
|
40
|
|
|
24
|
|
|
16
|
|
|
67
|
%
|
|||
Natural gas liquid sales
|
23
|
|
|
10
|
|
|
13
|
|
|
130
|
%
|
|||
Total product revenues
|
289
|
|
|
176
|
|
|
113
|
|
|
64
|
%
|
|||
Net gain (loss) on derivatives
|
116
|
|
|
(154
|
)
|
|
270
|
|
|
NM
|
|
|||
Gas management
|
8
|
|
|
116
|
|
|
(108
|
)
|
|
(93
|
)%
|
|||
Total revenues
|
$
|
413
|
|
|
$
|
138
|
|
|
$
|
275
|
|
|
199
|
%
|
•
|
$84 million
increase
in oil sales reflects $62 million related to higher production sales volumes and $22 million related to higher sales prices for the three months ended
June 30, 2017
compared to
2016
. The increase in production sales volumes relates to our Williston and Delaware Basins. The Williston Basin volumes were 30.1 MBbls per day compared to 20.0 MBbls per day for the three months ended
June 30, 2017
and
2016
, respectively. The Delaware Basin volumes were 20.2 MBbls per day compared to 13.8 MBbls per day for the three months ended
June 30, 2017
and
2016
, respectively. The Delaware Basin increase also includes the impact of the Panther Acquisition in the first quarter of 2017. The following table reflects oil production prices and volumes for the three months ended
June 30, 2017
and
2016
:
|
|
Three months
ended June 30, |
||||||
|
2017
|
|
2016
|
||||
|
|
||||||
Oil sales (per barrel)
|
42.46
|
|
|
$
|
38.38
|
|
|
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)
|
2.18
|
|
|
11.05
|
|
||
Oil net price including derivative settlements (per barrel)
|
$
|
44.64
|
|
|
$
|
49.43
|
|
|
|
|
|
||||
Oil production sales volumes (MBbls)
|
5,331
|
|
|
3,719
|
|
||
Per day oil production sales volumes (MBbls/d)
|
58.6
|
|
|
40.9
|
|
•
|
$16 million
increase
in natural gas sales reflects higher sales prices for the three months ended
June 30, 2017
compared to 2016. The following table reflects natural gas production prices and volumes for the three months ended
June 30, 2017
and
2016
:
|
|
Three months
ended June 30, |
||||||
|
2017
|
|
2016
|
||||
|
|
||||||
Natural gas sales (per Mcf)
|
$
|
2.13
|
|
|
1.23
|
|
|
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(a)
|
0.14
|
|
|
1.48
|
|
||
Natural gas net price including derivative settlements (per Mcf)
|
$
|
2.27
|
|
|
$
|
2.71
|
|
|
|
|
|
||||
Natural gas production sales volumes (MMcf)
|
18,475
|
|
|
18,764
|
|
||
Per day natural gas production sales volumes (MMcf/d)
|
203
|
|
|
206
|
|
•
|
$13 million
increase
in natural gas liquids sales reflects $9 million related to higher sales prices and $4 million related to increased production for the three months ended
June 30, 2017
compared to 2016. The increased production primarily relates to the Delaware Basin. The Delaware Basin volumes were 8.0 MBbls per day compared to 4.1 MBbls per day for the three months ended
June 30, 2017
and
2016
, respectively. The following table reflects NGL production prices and volumes for the three months ended
June 30, 2017
and
2016
:
|
|
Three months
ended June 30, |
||||||
|
2017
|
|
2016
|
||||
|
|
||||||
NGL sales (per barrel)
|
$
|
18.28
|
|
|
$
|
11.21
|
|
NGL production sales volumes (MBbls)
|
1,252
|
|
|
909
|
|
||
Per day NGL production sales volumes (MBbls/d)
|
13.8
|
|
|
10.0
|
|
•
|
$270 million
favorable
change in net gain (loss) on derivatives primarily reflects favorable change in gains (losses) on natural gas and crude derivatives due to decreases in 2017 of forward commodity prices relative to our hedge positions as opposed to increases in 2016 of forward commodity prices relative to our hedge position at that time. Net receipts on settlements for derivatives totaled
$14 million
and
$69 million
three months ended
June 30, 2017
and June 30, 2016, respectively.
|
•
|
$108 million
decrease
in gas management revenues is primarily due to lower natural gas sales volumes. The decrease in volumes is due in part to higher volumes in 2016 pursuant to a marketing agreement with the buyer of the Piceance Basin operations for a transition period that ended June 30, 2016 and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. A similar decrease is reflected in the
$124 million
decrease in related gas management costs and expenses, discussed below.
|
|
Three months
ended June 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|
Per Boe Expense
|
|||||||||||
|
2017
|
|
2016
|
|
|
2017
|
|
2016
|
||||||||||
|
(Millions)
|
|
|
|
|
|
|
|
|
|||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Depreciation, depletion and amortization
|
$
|
171
|
|
|
$
|
163
|
|
|
$
|
(8
|
)
|
|
(5
|
)%
|
|
$17.78
|
|
$21.02
|
Lease and facility operating
|
53
|
|
|
41
|
|
|
(12
|
)
|
|
(29
|
)%
|
|
$5.55
|
|
$5.34
|
|||
Gathering, processing and transportation
|
21
|
|
|
20
|
|
|
(1
|
)
|
|
(5
|
)%
|
|
$2.16
|
|
$2.57
|
|||
Taxes other than income
|
23
|
|
|
16
|
|
|
(7
|
)
|
|
(44
|
)%
|
|
$2.43
|
|
$2.05
|
|||
Exploration
|
21
|
|
|
12
|
|
|
(9
|
)
|
|
(75
|
)%
|
|
|
|
|
|||
General and administrative:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
General and administrative expenses
|
37
|
|
|
46
|
|
|
9
|
|
|
20
|
%
|
|
$3.84
|
|
$5.91
|
|||
Equity-based compensation
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
%
|
|
$0.96
|
|
$1.18
|
|||
Total general and administrative
|
46
|
|
|
55
|
|
|
9
|
|
|
16
|
%
|
|
$4.80
|
|
$7.09
|
|||
Gas management
|
8
|
|
|
132
|
|
|
124
|
|
|
94
|
%
|
|
|
|
|
|||
Net gain on sales of assets
|
(7
|
)
|
|
(4
|
)
|
|
3
|
|
|
75
|
%
|
|
|
|
|
|||
Other—net
|
8
|
|
|
2
|
|
|
(6
|
)
|
|
NM
|
|
|
|
|
|
|||
Total costs and expenses
|
$
|
344
|
|
|
$
|
437
|
|
|
$
|
93
|
|
|
21
|
%
|
|
|
|
|
Operating income (loss)
|
$
|
69
|
|
|
$
|
(299
|
)
|
|
$
|
368
|
|
|
NM
|
|
|
|
|
|
•
|
$8 million
increase
in depreciation, depletion and amortization is primarily due to increased production volumes offset by a $3.24 per Boe decrease in rate which was impacted by an increase in the reserves due to an increase in the 12-month average price and the addition of new wells with lower relative cost per Boe.
|
•
|
$12 million
increase
in lease and facility operating expenses primarily related to increased production volumes.
|
•
|
$7 million
increase
in taxes other than income relates to increased product revenues, previously discussed.
|
•
|
$9 million
increase
in exploration expenses is primarily due to higher unproved leasehold property impairment, amortization and expiration in 2017 (see Note 5 of Notes to Consolidated Financial Statements).
|
•
|
$9 million
decrease
in general and administrative expenses as the three months ended June 30, 2016 included $7 million for severance and relocation costs associated with workforce reductions and office consolidations. Our general and administration expenses for the three months ended June 30, 2017 included approximately $1 million of costs related to acquisition transition. We will continually challenge our levels of general and administrative costs, however, we believe our organizational size is conducive for future growth. Excluding the transition service costs and the severance and relocation costs, general and administrative expenses would have averaged $4.66 per Boe for the three months ended June 30, 2017 compared to $6.13 per Boe for the same period in 2016.
|
•
|
$124 million
decrease
in gas management expenses is primarily due to lower natural gas purchase volumes. The decrease in volumes is due in part to the marketing of the volumes for the purchaser of our Piceance Basin operations and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. Also included in gas management expenses for the three months ended June 30, 2016, is $11 million for unutilized pipeline capacity related to divested transportation contracts.
|
|
Three months
ended June 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2017
|
|
2016
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Operating income (loss)
|
$
|
69
|
|
|
$
|
(299
|
)
|
|
$
|
368
|
|
|
NM
|
|
Interest expense
|
(46
|
)
|
|
(53
|
)
|
|
7
|
|
|
13
|
%
|
|||
Investment income and other
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|
(100
|
)%
|
|||
Income (loss) from continuing operations before income taxes
|
23
|
|
|
(353
|
)
|
|
376
|
|
|
NM
|
|
|||
Benefit for income taxes
|
(53
|
)
|
|
(130
|
)
|
|
(77
|
)
|
|
(59
|
)%
|
|||
Income (loss) from continuing operations
|
76
|
|
|
(223
|
)
|
|
299
|
|
|
NM
|
|
|||
Income from discontinued operations
|
—
|
|
|
25
|
|
|
(25
|
)
|
|
(100
|
)%
|
|||
Net income (loss)
|
$
|
76
|
|
|
$
|
(198
|
)
|
|
274
|
|
|
NM
|
|
|
Six months
ended June 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2017
|
|
2016
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Revenues:
|
|
|
|
|
|
|
|
|||||||
Oil sales
|
$
|
414
|
|
|
$
|
239
|
|
|
$
|
175
|
|
|
73
|
%
|
Natural gas sales
|
84
|
|
|
49
|
|
|
35
|
|
|
71
|
%
|
|||
Natural gas liquid sales
|
44
|
|
|
15
|
|
|
29
|
|
|
193
|
%
|
|||
Total product revenues
|
542
|
|
|
303
|
|
|
239
|
|
|
79
|
%
|
|||
Net gain (loss) on derivatives
|
319
|
|
|
(97
|
)
|
|
416
|
|
|
NM
|
|
|||
Gas management
|
13
|
|
|
147
|
|
|
(134
|
)
|
|
(91
|
)%
|
|||
Other
|
—
|
|
|
1
|
|
|
(1
|
)
|
|
(100
|
)%
|
|||
Total revenues
|
$
|
874
|
|
|
$
|
354
|
|
|
$
|
520
|
|
|
147
|
%
|
•
|
$175 million
increase
in oil sales reflects $111 million related to higher sales prices and $64 million related to higher production sales volumes for the three months ended
June 30, 2017
compared to
2016
. The increase in production sales volumes relates to our Delaware and Williston Basins. The Delaware Basin volumes were 16.9 MBbls per day compared to 12.9 MBbls per day for the
six
months ended
June 30, 2017
and
2016
, respectively. The Williston Basin volumes were 27.7 MBbls per day compared to 20.9 MBbls per day for the
six
months ended
June 30, 2017
and
2016
, respectively. The following table reflects oil production prices and volumes for the
six
months ended
June 30, 2017
and
2016
:
|
|
Six months
ended June 30, |
||||||
|
2017
|
|
2016
|
||||
|
|
||||||
Oil sales (per barrel)
|
$
|
43.70
|
|
|
$
|
31.96
|
|
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)
|
0.90
|
|
|
15.50
|
|
||
Oil net price including derivative settlements (per barrel)
|
$
|
44.60
|
|
|
$
|
47.46
|
|
|
|
|
|
||||
Oil production sales volumes (MBbls)
|
9,479
|
|
|
7,493
|
|
||
Per day oil production sales volumes (MBbls/d)
|
52.4
|
|
|
41.2
|
|
•
|
$35 million
increase
in natural gas sales is primarily due to higher sales prices for the six months ended
June 30, 2017
compared to 2016. The increase in our production sales volumes relates to our Delaware Basin. In addition, 2016 natural gas volumes were negatively impacted by third-party processing constraints. The following table reflects natural gas production prices and volumes for the
six
months ended
June 30, 2017
and
2016
:
|
|
Six months
ended June 30, |
||||||
|
2017
|
|
2016
|
||||
|
|
||||||
Natural gas sales (per Mcf)
|
$
|
2.32
|
|
|
$
|
1.37
|
|
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(a)
|
0.01
|
|
|
2.39
|
|
||
Natural gas net price including derivative settlements (per Mcf)
|
$
|
2.33
|
|
|
$
|
3.76
|
|
|
|
|
|
||||
Natural gas production sales volumes (MMcf)
|
36,080
|
|
|
35,583
|
|
||
Per day natural gas production sales volumes (MMcf/d)
|
199
|
|
|
196
|
|
•
|
$29 million
increase
in natural gas liquids sales primarily reflects $23 million related to higher sales prices and $6 million related to increased production sales volumes for the six months ended
June 30, 2017
compared to 2016. The following table reflects NGL production prices and volumes for the
six
months ended
June 30, 2017
and
2016
:
|
|
Six months
ended June 30, |
||||||
|
2017
|
|
2016
|
||||
|
|
||||||
NGL sales (per barrel)
|
$
|
19.43
|
|
|
$
|
9.43
|
|
NGL production sales volumes (MBbls)
|
2,267
|
|
|
1,617
|
|
||
Per day NGL production sales volumes (MBbls/d)
|
12.5
|
|
|
8.9
|
|
•
|
$416 million
favorable
change in net gain (loss) on derivatives primarily reflects favorable change in gains (losses) on natural gas and crude derivatives due to decreases in forward commodity prices relative to our hedge positions. Net receipts on settlements on derivatives totaled
$9 million
and
$202 million
for the six months ended
June 30, 2017
and June 30, 2016, respectively.
|
•
|
$134 million
decrease
in gas management revenues is primarily due to lower natural gas sales volumes. The decrease in volumes is due in part to the sale of production volumes in 2016 pursuant to our purchase agreement with the buyer of the Piceance Basin operations and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. A similar decrease is reflected in the $
158 million
decrease in related gas management costs and expenses, discussed below.
|
|
Six months
ended June 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|
Per Boe Expense
|
|||||||||||
|
2017
|
|
2016
|
|
|
2017
|
|
2016
|
||||||||||
|
(Millions)
|
|
|
|
|
|
|
|
|
|||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Depreciation, depletion and amortization
|
$
|
318
|
|
|
$
|
315
|
|
|
$
|
(3
|
)
|
|
(1
|
)%
|
|
$17.93
|
|
$20.98
|
Lease and facility operating
|
101
|
|
|
83
|
|
|
(18
|
)
|
|
(22
|
)%
|
|
$5.69
|
|
$5.53
|
|||
Gathering, processing and transportation
|
42
|
|
|
36
|
|
|
(6
|
)
|
|
(17
|
)%
|
|
$2.38
|
|
$2.38
|
|||
Taxes other than income
|
42
|
|
|
27
|
|
|
(15
|
)
|
|
(56
|
)%
|
|
$2.38
|
|
$1.77
|
|||
Exploration
|
60
|
|
|
21
|
|
|
(39
|
)
|
|
(186
|
)%
|
|
|
|
|
|||
General and administrative:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
General and administrative expenses
|
73
|
|
|
93
|
|
|
20
|
|
|
22
|
%
|
|
$4.10
|
|
$6.18
|
|||
Equity-based compensation
|
16
|
|
|
15
|
|
|
(1
|
)
|
|
(7
|
)%
|
|
$0.92
|
|
$1.03
|
|||
Total general and administrative
|
89
|
|
|
108
|
|
|
19
|
|
|
18
|
%
|
|
$5.02
|
|
$7.21
|
|||
Gas management
|
13
|
|
|
171
|
|
|
158
|
|
|
92
|
%
|
|
|
|
|
|||
Net gain on sales of assets
|
(42
|
)
|
|
(202
|
)
|
|
(160
|
)
|
|
(79
|
)%
|
|
|
|
|
|||
Other—net
|
12
|
|
|
4
|
|
|
(8
|
)
|
|
(200
|
)%
|
|
|
|
|
|||
Total costs and expenses
|
$
|
635
|
|
|
$
|
563
|
|
|
$
|
(72
|
)
|
|
(13
|
)%
|
|
|
|
|
Operating income (loss)
|
$
|
239
|
|
|
$
|
(209
|
)
|
|
$
|
448
|
|
|
NM
|
|
|
|
|
|
•
|
$3 million
increase
in depreciation, depletion and amortization is primarily due increased production volumes offset by a $3.05 per Boe decrease in rate which was impacted by an increase in reserves due to an increase in the 12-month average price, new wells with lower relative cost per Boe.
|
•
|
$18 million
increase
in lease and facility operating expenses primarily related to increased production volumes.
|
•
|
$6 million
increase
in gathering, processing and transportation primarily due to higher costs in the San Juan Basin as a result of the sale of the gathering system in March of 2016 and higher volumes in the Delaware Basin.
|
•
|
$15 million
increase
in taxes other than income primarily relates to increased product revenues.
|
•
|
$39 million
increase
in exploration expenses is primarily due to unproved leasehold property impairment, amortization and expiration in 2017 which includes costs associated with certain expired leases in the Permian Basin in excess of the accumulated amortization balance recorded during first-quarter 2017. These leases were renewed in second-quarter 2017. See Note 5 of Notes to Consolidated Financial Statements.
|
•
|
$19 million
decrease
in general and administrative expenses primarily due to workforce reductions. In addition, the six months ended June 30, 2016 included $10 million for severance and relocation costs associated with workforce reductions and office consolidations. We will continually challenge our levels of general and administrative costs, however, we believe our organizational size is conducive for future growth. Excluding the severance and relocation costs, general and administrative expenses would have averaged $6.54 per Boe for 2016.
|
•
|
$158 million
decrease
in gas management expenses is primarily due to lower natural gas purchase volumes. The decrease in volumes is due in part to the marketing of the volumes for the purchaser of our Piceance Basin operations and the divestment of transportation contracts in the third quarter of 2016 that were related to our former Piceance Basin operations. Also included in gas management expenses for the
six
months ended June 30, 2016 is $21 million for unutilized pipeline capacity related to divested transportation contracts.
|
•
|
$42 million
net gain on sales of assets in 2017 compared to
$202 million
net gain on sales of assets in 2016. The 2016 gain primarily relates to the sale of the San Juan Basin gathering system. See Note
5
of Notes to Consolidated Financial Statements.
|
|
Six months
ended June 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2017
|
|
2016
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Operating income (loss)
|
$
|
239
|
|
|
$
|
(209
|
)
|
|
$
|
448
|
|
|
NM
|
|
Interest expense
|
(93
|
)
|
|
(110
|
)
|
|
17
|
|
|
15
|
%
|
|||
Investment income and other
|
2
|
|
|
1
|
|
|
1
|
|
|
100
|
%
|
|||
Income (loss) from continuing operations before income taxes
|
148
|
|
|
(318
|
)
|
|
466
|
|
|
NM
|
|
|||
Provision (benefit) for income taxes
|
(22
|
)
|
|
(95
|
)
|
|
(73
|
)
|
|
(77
|
)%
|
|||
Income (loss) from continuing operations
|
170
|
|
|
(223
|
)
|
|
393
|
|
|
NM
|
|
|||
Income (loss) from discontinued operations
|
(2
|
)
|
|
13
|
|
|
(15
|
)
|
|
NM
|
|
|||
Net income (loss)
|
$
|
168
|
|
|
$
|
(210
|
)
|
|
378
|
|
|
NM
|
|
•
|
our planned capital expenditures, excluding acquisitions, are estimated to be approximately $
990 million
to $
1,070 million
of which $940 million to $1,010 million relate to drilling and completions, including facilities. As of
June 30, 2017
, we have incurred $493 million of drilling and completion capital expenditures including facilities, approximately $63 million for land acquisitions and $40 million for infrastructure and other items not associated with drilling and completions; and
|
•
|
we have hedged a portion of our anticipated 2017 and 2018 oil and gas production as disclosed in Commodity Price Risk Management following this section.
|
•
|
lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices or inflation on operating costs;
|
•
|
inability to close the joint venture;
|
•
|
significantly lower than expected capital expenditures could result in the loss of undeveloped leasehold;
|
•
|
reduced access to our credit facility pursuant to our financial covenants; and
|
•
|
higher than expected development costs, including the impact of inflation.
|
Crude Oil
|
Jul - Dec 2017
|
|
2018
|
||||||||||
|
Volume
(Bbls/d) |
|
Weighted Average
Price ($/Bbl) |
|
Volume
(Bbls/d) |
|
Weighted Average
Price ($/Bbl) |
||||||
Fixed Price Swaps—WTI
|
50,750
|
|
|
$
|
50.26
|
|
|
55,500
|
|
|
$
|
52.69
|
|
Fixed Price Calls—WTI
|
4,500
|
|
|
$
|
56.47
|
|
|
13,000
|
|
|
$
|
58.89
|
|
Basis swaps—Midland
|
15,000
|
|
|
$
|
(0.60
|
)
|
|
13,000
|
|
|
$
|
(0.94
|
)
|
Natural Gas
|
Jul - Dec 2017
|
|
2018
|
||||||||||
|
Volume
(BBtu/d) |
|
Weighted Average
Price ($/MMBtu) |
|
Volume
(BBtu/d) |
|
Weighted Average
Price ($/MMBtu) |
||||||
Fixed Price Swaps—Henry Hub
|
170
|
|
|
$
|
3.02
|
|
|
185
|
|
|
$
|
2.98
|
|
Swaptions—Henry Hub
|
—
|
|
|
$
|
—
|
|
|
20
|
|
|
$
|
3.33
|
|
Fixed Price Calls—Henry Hub
|
16
|
|
|
$
|
4.50
|
|
|
16
|
|
|
$
|
4.75
|
|
Basis swaps—Permian
|
73
|
|
|
$
|
(0.20
|
)
|
|
43
|
|
|
$
|
(0.28
|
)
|
Basis swaps—San Juan
|
98
|
|
|
$
|
(0.18
|
)
|
|
50
|
|
|
$
|
(0.34
|
)
|
Basis swaps—Waha
|
—
|
|
|
$
|
—
|
|
|
63
|
|
|
$
|
(0.16
|
)
|
|
Six months
ended June 30, |
||||||
|
2017
|
|
2016
|
||||
|
(Millions)
|
||||||
Net cash provided by (used in):
|
|
|
|
||||
Operating activities
|
$
|
142
|
|
|
$
|
89
|
|
Investing activities
|
(1,308
|
)
|
|
844
|
|
||
Financing activities
|
678
|
|
|
60
|
|
||
Net increase (decrease) in cash and cash equivalents
|
$
|
(488
|
)
|
|
$
|
993
|
|
|
|
Six months
ended June 30, |
||||||
|
|
2017
|
|
2016
|
||||
|
|
|
||||||
Cash capital expenditures for drilling and completions:
|
|
|
|
|
||||
Continuing operations
|
|
$
|
416
|
|
|
$
|
241
|
|
Discontinued operations
|
|
—
|
|
|
25
|
|
||
Total
|
|
$
|
416
|
|
|
$
|
266
|
|
|
|
|
|
|
||||
Capital expenditures incurred for drilling and completions:
|
|
|
|
|
||||
Continuing operations
|
|
$
|
457
|
|
|
$
|
224
|
|
Discontinued operations
|
|
—
|
|
|
21
|
|
||
Total
|
|
$
|
457
|
|
|
$
|
245
|
|
|
|
|
|
|
||||
Land acquisitions
|
|
$
|
63
|
|
|
$
|
—
|
|
Exhibit No.
|
|
Description
|
|
|
|
2.1**
|
|
Agreement and Plan of Merger, dated October 2, 2014, by and among Pluspetrol Resources Corporation, Pluspetrol Black River Corporation and Apco Oil and Gas International Inc. (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on October 7, 2014)
|
|
|
|
2.2**
|
|
Agreement and Plan of Merger, dated as of July 13, 2015, by and among RKI Exploration & Production, LLC, WPX Energy, Inc. and Thunder Merger Sub LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
|
|
|
|
2.3**
|
|
Membership Interest Purchase Agreement by and Among WPX Energy Holdings, LLC, as Seller, WPX Energy, Inc., solely for purposes of Section 14.15, and Terra Energy Partners LLC, as Purchaser, dated February 8, 2016 (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2016)
|
|
|
|
2.4**
|
|
Purchase and Sale Agreement, dated as of January 12, 2017, by and among RKI Exploration & Production, LLC, Panther Energy Company II, LLC and CP2 Operating, LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 13, 2017)
|
|
|
|
3.1
|
|
Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)
|
|
|
|
3.2
|
|
Certificate of Amendment of Amended and Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
|
|
|
|
3.3
|
|
Amended and Restated Bylaws of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 21, 2014)
|
|
|
|
3.4
|
|
Certificate of Designations for 6.25% Series A Mandatory Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
|
|
|
|
4.1
|
|
Indenture, dated as of November 14, 2011, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to The Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) filed with the SEC on November 15, 2011)
|
|
|
|
4.2
|
|
Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
|
|
|
|
4.3
|
|
First Supplemental Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
|
|
|
|
4.4
|
|
Second Supplemental Indenture, dated as of July 22, 2015, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
|
|
|
|
10.1
|
|
Separation and Distribution Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011)
|
|
|
|
10.2
|
|
Employee Matters Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)
|
|
|
|
10.3
|
|
Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on January 6, 2012)
|
|
|
|
10.4
|
|
WPX Energy, Inc. 2013 Incentive Plan (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 29, 2013) (1)
|
|
|
|
10.5
|
|
WPX Energy, Inc. 2011 Employee Stock Purchase Plan (incorporated herein by reference to Exhibit 4.4 to WPX Energy, Inc.’s registration statement on Form S-8 (File No. 333-178388) filed with the SEC on December 8, 2011) (1)
|
|
|
|
Exhibit No.
|
|
Description
|
10.6
|
|
Form of Restricted Stock Agreement between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011) (1)
|
|
|
|
10.7
|
|
Form of Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
|
|
|
|
10.8
|
|
Form of Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
|
|
|
|
10.9
|
|
Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015) (1)
|
|
|
|
10.10
|
|
Form of Stock Option Agreement between WPX Energy, Inc. and Section 16 Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014) (1)
|
|
|
|
10.11
|
|
WPX Energy Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.16 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012) (1)
|
|
|
|
10.12
|
|
WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.17 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012) (1)
|
|
|
|
10.13
|
|
Retirement Agreement, dated December 16, 2013, between WPX Energy, Inc. and Ralph A. Hill (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on December 17, 2013)
|
|
|
|
10.14
|
|
Employment Agreement, dated April 29, 2014, between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.15
|
|
Form of Nonqualified Stock Option Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.16
|
|
Form of 2014 Time-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.17
|
|
Form of 2014 Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.4 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.18
|
|
Form of Time-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.5 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.19
|
|
Form of Performance-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.6 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.20
|
|
Form of Restricted Stock Unit Award between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)
|
|
|
|
10.21
|
|
Separation and Release Agreement, dated July 28, 2014, between WPX Energy, Inc. and James J. Bender (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)
|
|
|
|
Exhibit No.
|
|
Description
|
10.22
|
|
Amended and Restated Credit Agreement, dated as of October 28, 2014, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 3, 2014)
|
|
|
|
10.23
|
|
Form of Voting and Support Agreement, dated as of July 13, 2015, by and between WPX Energy, Inc. and the Member signatory thereto (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
|
|
|
|
10.24
|
|
First Amendment to the Amended and Restated Credit Agreement, dated as of July 16, 2015, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as existing Administrative Agent and existing Swingline Lender, and Wells Fargo Bank, National Association, as successor Administrative Agent and successor Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
|
|
|
|
10.25
|
|
Commitment Increase Agreement for Amended and Restated Credit Agreement, dated as of July 31, 2015, among WPX Energy, Inc., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent, and the Issuing Banks thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on August 6, 2015)
|
|
|
|
10.26
|
|
Registration Rights Agreement dated August 17, 2015, among WPX Energy, Inc. and the signatures thereto (incorporated herein by reference to Exhibit 10.35 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015)
|
|
|
|
10.27
|
|
Second Amendment to the Amended and Restated Credit Agreement, dated as of March 18, 2016, by and among WPX Energy, Inc., as the borrower thereunder, the financial institutions party thereto from time to time, as lenders, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 22, 2016)
|
|
|
|
10.28
|
|
Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.32 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016) (1)
|
|
|
|
10.29
|
|
Form of Severance and Restrictive Covenant Agreement between WPX Energy, Inc. and Marcia MacLeod (incorporated herein by reference to Exhibit 10.33 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016) (1)
|
|
|
|
10.30
|
|
Form of Severance and Restrictive Covenant Agreement between WPX Energy, Inc. and Michael Fiser (incorporated herein by reference to Exhibit 10.33 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016) (1)
|
|
|
|
10.31
|
|
Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and CEO (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 9, 2016) (1)
|
|
|
|
10.32
|
|
Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and Tier One Executives (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 9, 2016) (1)
|
|
|
|
10.33
|
|
Amended and Restated WPX Energy Executive Severance Pay Plan (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 23, 2017) (1)
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12*
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Computation of Ratio of Earnings to Fixed Charges
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31.1*
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Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
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31.2*
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Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
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32.1*
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Certification by the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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101.INS*
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XBRL Instance Document
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101.SCH*
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XBRL Taxonomy Extension Schema
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101.CAL*
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XBRL Taxonomy Extension Calculation Linkbase
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101.DEF*
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XBRL Taxonomy Extension Definition Linkbase
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Exhibit No.
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Description
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101.LAB*
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XBRL Taxonomy Extension Label Linkbase
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101.PRE*
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XBRL Taxonomy Extension Presentation Linkbase
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*
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Filed herewith
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**
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All schedules to the Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the SEC upon request
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(1)
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Management contract or compensatory plan or arrangement
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WPX Energy, Inc.
(Registrant)
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||
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By:
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/s/ Stephen L. Faulkner
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Stephen L. Faulkner
Controller
(Principal Accounting Officer)
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Six months
ended June 30, |
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2017
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(Millions)
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Earnings:
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Income from continuing operations before income taxes
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$
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148
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Add:
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Fixed Charges:
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Interest accrued, including proportionate share from 50% owned investees and unconsolidated majority-owned investees (a)
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93
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Rental expense representative of interest factor
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3
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Total fixed charges
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96
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Total earnings as adjusted
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$
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244
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Fixed charges
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$
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96
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Ratio of earnings to fixed charges
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2.54
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Preferred dividend requirement
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$
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12
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Combined fixed charges and preferred dividends
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108
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Ratio of earnings to combined fixed charges and preferred dividends
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$
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2.26
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(a)
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Does not include interest related to income taxes, including interest related to liabilities for uncertain tax positions, which is included in the provision for income taxes
in our Consolidated Statements of Operations.
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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b)
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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c)
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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d)
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
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a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
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b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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/s/ Richard E. Muncrief
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Richard E. Muncrief
Chief Executive Officer
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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b)
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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c)
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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d)
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
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a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
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b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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/s/ J. Kevin Vann
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J. Kevin Vann
Chief Financial Officer
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/s/ Richard E. Muncrief
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Richard E. Muncrief
President and Chief Executive Officer
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August 3, 2017
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/s/ J. Kevin Vann
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J. Kevin Vann
Senior Vice President and Chief Financial Officer
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August 3, 2017
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