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Share Name | Share Symbol | Market | Type |
---|---|---|---|
WPX Energy Inc | NYSE:WPX | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 9.43 | 0 | 01:00:00 |
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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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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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|
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Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017
|
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Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and 2017
|
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Consolidated Statements of Changes in Equity for the nine months ended September 30, 2018
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Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017
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Item 2.
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||
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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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||
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Item 1A.
|
||
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Item 2.
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||
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Item 3.
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||
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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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expansion and growth of our business and operations;
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•
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financial condition and liquidity;
|
•
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business strategy;
|
•
|
estimates of proved oil and natural gas reserves;
|
•
|
reserve potential;
|
•
|
development drilling potential;
|
•
|
cash flow from operations or results of operations;
|
•
|
acquisitions or divestitures;
|
•
|
seasonality of our business; and
|
•
|
crude oil, natural gas and NGL prices and demand.
|
•
|
availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future oil and natural gas reserves), market demand, volatility of commodity prices and the availability and cost of capital;
|
•
|
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);
|
•
|
the strength and financial resources of our competitors;
|
•
|
development of alternative energy sources;
|
•
|
the impact of operational and development hazards;
|
•
|
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;
|
•
|
changes in maintenance and construction costs;
|
•
|
changes in the current geopolitical situation;
|
•
|
our exposure to the credit risk of our customers;
|
•
|
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;
|
•
|
risks associated with future weather conditions;
|
•
|
acts of terrorism;
|
•
|
other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”; and
|
•
|
additional risks described in our filings with the Securities and Exchange Commission (“SEC”).
|
|
September 30,
2018 |
|
December 31,
2017 |
||||
|
(Millions)
|
||||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
36
|
|
|
$
|
189
|
|
Accounts receivable, net of allowance of $2 million as of September 30, 2018 and December 31, 2017
|
368
|
|
|
307
|
|
||
Derivative assets
|
98
|
|
|
36
|
|
||
Inventories
|
49
|
|
|
30
|
|
||
Assets classified as held for sale (Note 2)
|
—
|
|
|
811
|
|
||
Other
|
27
|
|
|
28
|
|
||
Total current assets
|
578
|
|
|
1,401
|
|
||
Investments
|
139
|
|
|
70
|
|
||
Properties and equipment (successful efforts method of accounting)
|
9,663
|
|
|
8,674
|
|
||
Less—accumulated depreciation, depletion and amortization
|
(2,511
|
)
|
|
(1,983
|
)
|
||
Properties and equipment, net
|
7,152
|
|
|
6,691
|
|
||
Derivative assets
|
22
|
|
|
23
|
|
||
Other noncurrent assets
|
27
|
|
|
22
|
|
||
Total assets
|
$
|
7,918
|
|
|
$
|
8,207
|
|
|
|
|
|
||||
Liabilities and Equity
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
607
|
|
|
$
|
446
|
|
Accrued and other current liabilities
|
155
|
|
|
209
|
|
||
Liabilities associated with assets held for sale (Note 2)
|
—
|
|
|
20
|
|
||
Derivative liabilities
|
369
|
|
|
171
|
|
||
Total current liabilities
|
1,131
|
|
|
846
|
|
||
Deferred income taxes
|
33
|
|
|
117
|
|
||
Long-term debt, net
|
2,243
|
|
|
2,575
|
|
||
Derivative liabilities
|
73
|
|
|
65
|
|
||
Other noncurrent liabilities
|
499
|
|
|
477
|
|
||
Contingent liabilities and commitments (Note 8)
|
|
|
|
||||
Equity:
|
|
|
|
||||
Stockholders’ equity:
|
|
|
|
||||
Preferred stock (100 million shares authorized at $0.01 par value; no shares outstanding at September 30, 2018 and 4.8 million shares outstanding at December 31, 2017)
|
—
|
|
|
232
|
|
||
Common stock (2 billion shares authorized at $0.01 par value; 420.4 million and 398.3 million shares issued and outstanding at September 30, 2018 and December 31, 2017)
|
4
|
|
|
4
|
|
||
Additional paid-in-capital
|
7,726
|
|
|
7,479
|
|
||
Accumulated deficit
|
(3,791
|
)
|
|
(3,588
|
)
|
||
Total stockholders’ equity
|
3,939
|
|
|
4,127
|
|
||
Total liabilities and equity
|
$
|
7,918
|
|
|
$
|
8,207
|
|
|
Three months
ended September 30, |
|
Nine months
ended September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Revenues:
|
(Millions, except per-share amounts)
|
||||||||||||||
Product revenues:
|
|
|
|
|
|
|
|
||||||||
Oil sales
|
$
|
503
|
|
|
$
|
218
|
|
|
$
|
1,331
|
|
|
$
|
571
|
|
Natural gas sales
|
18
|
|
|
13
|
|
|
51
|
|
|
46
|
|
||||
Natural gas liquid sales
|
33
|
|
|
16
|
|
|
99
|
|
|
43
|
|
||||
Total product revenues
|
554
|
|
|
247
|
|
|
1,481
|
|
|
660
|
|
||||
Net gain (loss) on derivatives
|
(139
|
)
|
|
(106
|
)
|
|
(362
|
)
|
|
213
|
|
||||
Commodity management
|
68
|
|
|
4
|
|
|
168
|
|
|
17
|
|
||||
Other
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
Total revenues
|
484
|
|
|
145
|
|
|
1,288
|
|
|
890
|
|
||||
Costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Depreciation, depletion and amortization
|
193
|
|
|
133
|
|
|
551
|
|
|
387
|
|
||||
Lease and facility operating
|
68
|
|
|
45
|
|
|
182
|
|
|
122
|
|
||||
Gathering, processing and transportation
|
26
|
|
|
5
|
|
|
64
|
|
|
16
|
|
||||
Taxes other than income
|
45
|
|
|
19
|
|
|
116
|
|
|
51
|
|
||||
Exploration (Note 4)
|
18
|
|
|
17
|
|
|
54
|
|
|
69
|
|
||||
General and administrative (including equity-based compensation of $8 million, $7 million, $25 million and $22 million for the respective periods)
|
44
|
|
|
40
|
|
|
131
|
|
|
125
|
|
||||
Commodity management
|
63
|
|
|
4
|
|
|
156
|
|
|
17
|
|
||||
Net gain on sales of assets (Note 4)
|
(1
|
)
|
|
(112
|
)
|
|
(1
|
)
|
|
(150
|
)
|
||||
Other—net
|
2
|
|
|
4
|
|
|
6
|
|
|
15
|
|
||||
Total costs and expenses
|
458
|
|
|
155
|
|
|
1,259
|
|
|
652
|
|
||||
Operating income (loss)
|
26
|
|
|
(10
|
)
|
|
29
|
|
|
238
|
|
||||
Interest expense
|
(38
|
)
|
|
(48
|
)
|
|
(123
|
)
|
|
(141
|
)
|
||||
Loss on extinguishment of debt
|
—
|
|
|
(17
|
)
|
|
(71
|
)
|
|
(17
|
)
|
||||
Investment income (loss) and other
|
(2
|
)
|
|
2
|
|
|
(2
|
)
|
|
4
|
|
||||
Income (loss) from continuing operations before income taxes
|
(14
|
)
|
|
(73
|
)
|
|
(167
|
)
|
|
84
|
|
||||
Provision (benefit) for income taxes
|
(8
|
)
|
|
305
|
|
|
(56
|
)
|
|
40
|
|
||||
Income (loss) from continuing operations
|
(6
|
)
|
|
(378
|
)
|
|
(111
|
)
|
|
44
|
|
||||
Income (loss) from discontinued operations
|
(1
|
)
|
|
232
|
|
|
(92
|
)
|
|
(22
|
)
|
||||
Net income (loss)
|
(7
|
)
|
|
(146
|
)
|
|
(203
|
)
|
|
22
|
|
||||
Less: Dividends on preferred stock
|
—
|
|
|
3
|
|
|
8
|
|
|
11
|
|
||||
Net income (loss) available to WPX Energy, Inc. common stockholders
|
$
|
(7
|
)
|
|
$
|
(149
|
)
|
|
$
|
(211
|
)
|
|
$
|
11
|
|
Amounts available to WPX Energy, Inc. common stockholders:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
(6
|
)
|
|
$
|
(381
|
)
|
|
$
|
(119
|
)
|
|
$
|
33
|
|
Income (loss) from discontinued operations
|
(1
|
)
|
|
232
|
|
|
(92
|
)
|
|
(22
|
)
|
||||
Net income (loss)
|
$
|
(7
|
)
|
|
$
|
(149
|
)
|
|
$
|
(211
|
)
|
|
$
|
11
|
|
Basic earnings (loss) per common share:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
(0.01
|
)
|
|
$
|
(0.96
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
0.08
|
|
Income (loss) from discontinued operations
|
—
|
|
|
0.58
|
|
|
(0.23
|
)
|
|
(0.05
|
)
|
||||
Net income (loss)
|
$
|
(0.01
|
)
|
|
$
|
(0.38
|
)
|
|
$
|
(0.52
|
)
|
|
$
|
0.03
|
|
Basic weighted-average shares
|
414.0
|
|
|
398.1
|
|
|
404.3
|
|
|
394.1
|
|
||||
Diluted earnings (loss) per common share:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
(0.01
|
)
|
|
$
|
(0.96
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
0.08
|
|
Income (loss) from discontinued operations
|
—
|
|
|
0.58
|
|
|
(0.23
|
)
|
|
(0.05
|
)
|
||||
Net income (loss)
|
$
|
(0.01
|
)
|
|
$
|
(0.38
|
)
|
|
$
|
(0.52
|
)
|
|
$
|
0.03
|
|
Diluted weighted-average shares
|
414.0
|
|
|
398.1
|
|
|
404.3
|
|
|
396.2
|
|
|
WPX Energy, Inc., Stockholders
|
||||||||||||||||||
|
Preferred Stock
|
|
Common
Stock
|
|
Additional
Paid-In-
Capital
|
|
Accumulated
Deficit
|
|
Total
Stockholders’
Equity
|
||||||||||
|
|
|
|
||||||||||||||||
Balance at December 31, 2017
|
$
|
232
|
|
|
$
|
4
|
|
|
$
|
7,479
|
|
|
$
|
(3,588
|
)
|
|
$
|
4,127
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(203
|
)
|
|
(203
|
)
|
|||||
Stock-based compensation, net of tax impact
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
|
23
|
|
|||||
Conversion of preferred stock to common stock
|
(232
|
)
|
|
—
|
|
|
232
|
|
|
—
|
|
|
—
|
|
|||||
Dividends on preferred stock
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
(8
|
)
|
|||||
Balance at September 30, 2018
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
7,726
|
|
|
$
|
(3,791
|
)
|
|
$
|
3,939
|
|
|
Nine months
ended September 30, |
||||||
|
2018
|
|
2017
|
||||
Operating Activities(a)
|
(Millions)
|
||||||
Net income (loss)
|
$
|
(203
|
)
|
|
$
|
22
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
||||
Depreciation, depletion and amortization
|
559
|
|
|
487
|
|
||
Deferred income tax provision (benefit)
|
(84
|
)
|
|
25
|
|
||
Provision for impairment of properties and equipment (including certain exploration expenses)
|
53
|
|
|
138
|
|
||
Net (gain) loss on derivatives
|
362
|
|
|
(213
|
)
|
||
Net settlements related to derivatives
|
(218
|
)
|
|
23
|
|
||
Amortization of stock-based awards
|
26
|
|
|
24
|
|
||
Loss on extinguishment of debt
|
71
|
|
|
17
|
|
||
Net (gain) loss on sales of assets including discontinued operations
|
150
|
|
|
(157
|
)
|
||
Cash provided by (used in) operating assets and liabilities:
|
|
|
|
||||
Accounts receivable
|
(61
|
)
|
|
(112
|
)
|
||
Inventories
|
(15
|
)
|
|
(6
|
)
|
||
Other current assets
|
5
|
|
|
(6
|
)
|
||
Accounts payable
|
71
|
|
|
91
|
|
||
Federal income taxes receivable
|
—
|
|
|
12
|
|
||
Accrued and other current liabilities
|
(48
|
)
|
|
(86
|
)
|
||
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations
|
(37
|
)
|
|
(40
|
)
|
||
Other, including changes in other noncurrent assets and liabilities
|
21
|
|
|
9
|
|
||
Net cash provided by operating activities(a)
|
652
|
|
|
228
|
|
||
Investing Activities(a)
|
|
|
|
||||
Capital expenditures(b)
|
(1,013
|
)
|
|
(855
|
)
|
||
Proceeds from sales of assets
|
682
|
|
|
34
|
|
||
Purchase of a business
|
—
|
|
|
(798
|
)
|
||
Purchase of or contributions to investments
|
(72
|
)
|
|
(7
|
)
|
||
Net cash used in investing activities(a)
|
(403
|
)
|
|
(1,626
|
)
|
||
Financing Activities
|
|
|
|
||||
Proceeds from common stock
|
9
|
|
|
671
|
|
||
Dividends paid on preferred stock
|
(11
|
)
|
|
(11
|
)
|
||
Borrowings on credit facility
|
726
|
|
|
471
|
|
||
Payments on credit facility
|
(638
|
)
|
|
(186
|
)
|
||
Proceeds from long-term debt, net of discount
|
494
|
|
|
148
|
|
||
Payments for retirement of long-term debt, including premium
|
(986
|
)
|
|
(165
|
)
|
||
Taxes paid for shares withheld
|
(13
|
)
|
|
(11
|
)
|
||
Payments for debt issuance costs and credit facility amendment fees
|
(10
|
)
|
|
(2
|
)
|
||
Other
|
29
|
|
|
(1
|
)
|
||
Net cash provided by (used in) financing activities
|
(400
|
)
|
|
914
|
|
||
Net decrease in cash and cash equivalents and restricted cash
|
(151
|
)
|
|
(484
|
)
|
||
Cash and cash equivalents and restricted cash at beginning of period
|
201
|
|
|
506
|
|
||
Cash and cash equivalents and restricted cash at end of period
|
$
|
50
|
|
|
$
|
22
|
|
__________
|
|
|
|
||||
(a) Amounts reflect continuing and discontinued operations unless otherwise noted. See Note 2 of Notes to Consolidated Financial Statements for discussion of discontinued operations.
|
|
|
|
||||
(b) Increase to properties and equipment
|
$
|
(1,074
|
)
|
|
$
|
(911
|
)
|
Changes in related accounts payable and accounts receivable
|
61
|
|
|
56
|
|
||
Capital expenditures
|
$
|
(1,013
|
)
|
|
$
|
(855
|
)
|
|
Three months
ended September 30, |
|
Nine months
ended September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(Millions)
|
||||||||||||||
Total revenues
|
$
|
—
|
|
|
$
|
79
|
|
|
$
|
75
|
|
|
$
|
208
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Depreciation, depletion and amortization
|
$
|
—
|
|
|
$
|
36
|
|
|
$
|
8
|
|
|
$
|
100
|
|
Lease and facility operating
|
—
|
|
|
13
|
|
|
7
|
|
|
37
|
|
||||
Gathering, processing and transportation
|
—
|
|
|
20
|
|
|
12
|
|
|
51
|
|
||||
Taxes other than income
|
—
|
|
|
7
|
|
|
5
|
|
|
17
|
|
||||
General and administrative
|
—
|
|
|
2
|
|
|
1
|
|
|
6
|
|
||||
Exploration
|
—
|
|
|
3
|
|
|
3
|
|
|
11
|
|
||||
Impairment of assets held for sale
|
—
|
|
|
60
|
|
|
—
|
|
|
60
|
|
||||
Gain on sales of assets
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(8
|
)
|
||||
Accretion for transportation and gathering obligations retained
|
2
|
|
|
2
|
|
|
5
|
|
|
5
|
|
||||
Other—net(a)
|
—
|
|
|
(9
|
)
|
|
4
|
|
|
(8
|
)
|
||||
Total costs and expenses
|
2
|
|
|
130
|
|
|
45
|
|
|
271
|
|
||||
Operating income (loss)
|
(2
|
)
|
|
(51
|
)
|
|
30
|
|
|
(63
|
)
|
||||
Loss on sale of assets
|
(1
|
)
|
|
—
|
|
|
(151
|
)
|
|
—
|
|
||||
Loss from discontinued operations before income taxes
|
(3
|
)
|
|
(51
|
)
|
|
(121
|
)
|
|
(63
|
)
|
||||
Income tax benefit
|
(2
|
)
|
|
(283
|
)
|
|
(29
|
)
|
|
(41
|
)
|
||||
Income (loss) from discontinued operations
|
$
|
(1
|
)
|
|
$
|
232
|
|
|
$
|
(92
|
)
|
|
$
|
(22
|
)
|
|
December 31,
|
||
|
2017
|
||
|
(Millions)
|
||
Assets classified as held for sale
|
|
||
Inventories
|
$
|
14
|
|
Properties and equipment, net (successful efforts method of accounting)
|
797
|
|
|
Total assets classified as held for sale on the Consolidated Balance Sheets
|
$
|
811
|
|
|
|
||
Liabilities associated with assets held for sale
|
|
||
Current liabilities:
|
|
||
Accounts payable
|
$
|
1
|
|
Accrued and other current liabilities
|
1
|
|
|
Total current liabilities
|
2
|
|
|
Asset retirement obligations
|
15
|
|
|
Other noncurrent liabilities
|
3
|
|
|
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets
|
$
|
20
|
|
|
Nine months
ended September 30, |
||||||
|
2018
|
|
2017
|
||||
|
(Millions)
|
||||||
Cash provided by operating activities(a)
|
$
|
44
|
|
|
$
|
41
|
|
Cash capital expenditures within investing activities
|
$
|
29
|
|
|
$
|
137
|
|
|
Three months
ended September 30, |
|
Nine months
ended September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(Millions, except per-share amounts)
|
||||||||||||||
Income (loss) from continuing operations
|
$
|
(6
|
)
|
|
$
|
(378
|
)
|
|
$
|
(111
|
)
|
|
$
|
44
|
|
Less: Dividends on preferred stock
|
—
|
|
|
3
|
|
|
8
|
|
|
11
|
|
||||
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share
|
$
|
(6
|
)
|
|
$
|
(381
|
)
|
|
$
|
(119
|
)
|
|
$
|
33
|
|
|
|
|
|
|
|
|
|
||||||||
Basic weighted-average shares
|
414.0
|
|
|
398.1
|
|
|
404.3
|
|
|
394.1
|
|
||||
Effect of dilutive securities(a):
|
|
|
|
|
|
|
|
||||||||
Nonvested restricted stock units and awards
|
—
|
|
|
—
|
|
|
—
|
|
|
1.9
|
|
||||
Stock options
|
—
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
||||
Diluted weighted-average shares
|
414.0
|
|
|
398.1
|
|
|
404.3
|
|
|
396.2
|
|
||||
Earnings (loss) per common share from continuing operations:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.01
|
)
|
|
$
|
(0.96
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
0.08
|
|
Diluted
|
$
|
(0.01
|
)
|
|
$
|
(0.96
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
0.08
|
|
|
Three months
ended September 30, |
|
Nine months
ended September 30, |
||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||
|
(Millions)
|
||||||||||
Weighted-average nonvested restricted stock units and awards
|
3.5
|
|
|
1.6
|
|
|
3.1
|
|
|
—
|
|
Weighted-average stock options
|
0.2
|
|
|
0.1
|
|
|
0.2
|
|
|
—
|
|
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock
|
—
|
|
|
23.8
|
|
|
—
|
|
|
23.8
|
|
Nonvested restricted stock units antidilutive under the treasury stock method
|
—
|
|
|
2.0
|
|
|
—
|
|
|
2.0
|
|
|
September 30,
|
||||||
|
2018
|
|
2017
|
||||
Options excluded (millions)
|
0.1
|
|
|
1.9
|
|
||
Weighted-average exercise price of options excluded
|
$
|
21.51
|
|
|
$
|
16.69
|
|
Exercise price range of options excluded
|
$21.45 - $21.81
|
|
|
$11.75 - $21.81
|
|
||
Third quarter weighted-average market price
|
$
|
18.53
|
|
|
$
|
10.23
|
|
|
Three months
ended September 30, |
|
Nine months
ended September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(Millions)
|
||||||||||||||
Unproved leasehold property impairment, amortization and expiration
|
$
|
18
|
|
|
$
|
17
|
|
|
$
|
51
|
|
|
$
|
67
|
|
Geologic and geophysical costs
|
—
|
|
|
—
|
|
|
3
|
|
|
2
|
|
||||
Total exploration expenses
|
$
|
18
|
|
|
$
|
17
|
|
|
$
|
54
|
|
|
$
|
69
|
|
|
September 30,
2018 |
|
December 31,
2017 |
||||
|
(Millions)
|
||||||
Material, supplies and other
|
$
|
43
|
|
|
$
|
29
|
|
Commodity production in transit or storage
|
6
|
|
|
1
|
|
||
Total inventories
|
$
|
49
|
|
|
$
|
30
|
|
|
September 30,
2018 |
|
December 31,
2017 |
||||
|
(Millions)
|
||||||
Credit facility agreement
|
$
|
88
|
|
|
$
|
—
|
|
7.500% Senior Notes due 2020
|
—
|
|
|
350
|
|
||
6.000% Senior Notes due 2022
|
529
|
|
|
1,100
|
|
||
8.250% Senior Notes due 2023
|
500
|
|
|
500
|
|
||
5.250% Senior Notes due 2024
|
650
|
|
|
650
|
|
||
5.750% Senior Notes due 2026
|
500
|
|
|
—
|
|
||
Total long-term debt
|
$
|
2,267
|
|
|
$
|
2,600
|
|
Less: Debt issuance costs on long-term debt(a)
|
24
|
|
|
25
|
|
||
Total long-term debt, net(a)
|
$
|
2,243
|
|
|
$
|
2,575
|
|
•
|
a ratio of Net Indebtedness to Consolidated EBITDAX for the most recent ended four consecutive fiscal quarters (excluding the first three quarters of 2018 which will use an Annualized Consolidated EBITDAX) of not greater than
4.25
to 1.00 as of the last day of the most recently ended Rolling Period; and
|
•
|
a ratio of consolidated current assets (including the unused amount of the Aggregate Commitments) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least
1.0
to 1.0.
|
|
Three months
ended September 30, |
|
Nine months
ended September 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(Millions)
|
||||||||||||||
Current:
|
|
|
|
|
|
|
|
||||||||
Federal
|
$
|
—
|
|
|
$
|
(27
|
)
|
|
$
|
—
|
|
|
$
|
(27
|
)
|
State
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
||||
|
(1
|
)
|
|
(27
|
)
|
|
(1
|
)
|
|
(27
|
)
|
||||
Deferred:
|
|
|
|
|
|
|
|
||||||||
Federal
|
(6
|
)
|
|
34
|
|
|
(43
|
)
|
|
62
|
|
||||
State
|
(1
|
)
|
|
298
|
|
|
(12
|
)
|
|
5
|
|
||||
|
(7
|
)
|
|
332
|
|
|
(55
|
)
|
|
67
|
|
||||
Total provision (benefit)
|
$
|
(8
|
)
|
|
$
|
305
|
|
|
$
|
(56
|
)
|
|
$
|
40
|
|
|
September 30, 2018
|
|
December 31, 2017
|
||||||||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||
|
(Millions)
|
|
(Millions)
|
||||||||||||||||||||||||||||
Energy derivative assets
|
$
|
—
|
|
|
$
|
120
|
|
|
$
|
—
|
|
|
$
|
120
|
|
|
$
|
—
|
|
|
$
|
59
|
|
|
$
|
—
|
|
|
$
|
59
|
|
Energy derivative liabilities
|
$
|
—
|
|
|
$
|
442
|
|
|
$
|
—
|
|
|
$
|
442
|
|
|
$
|
—
|
|
|
$
|
236
|
|
|
$
|
—
|
|
|
$
|
236
|
|
Total debt(a)
|
$
|
—
|
|
|
$
|
2,364
|
|
|
$
|
—
|
|
|
$
|
2,364
|
|
|
$
|
—
|
|
|
$
|
2,746
|
|
|
$
|
—
|
|
|
$
|
2,746
|
|
(a)
|
The carrying value of total debt, excluding capital leases and debt issuance costs, was
$2,267 million
and
$2,600 million
as of
September 30, 2018
and
December 31, 2017
, 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
|
|
Oct - Dec 2018
|
|
Fixed Price Swaps
|
|
WTI
|
|
(57,500
|
)
|
|
$
|
52.82
|
|
Crude Oil
|
|
Oct - Dec 2018
|
|
Basis Swaps
|
|
Midland/Cushing
|
|
(14,000
|
)
|
|
$
|
(0.77
|
)
|
Crude Oil
|
|
Oct - Dec 2018
|
|
Basis Swaps
|
|
Nymex CMA Roll
|
|
(13,261
|
)
|
|
$
|
0.03
|
|
Crude Oil
|
|
Oct - Dec 2018
|
|
Basis Swaps
|
|
Argus LLS/Cushing
|
|
(5,000
|
)
|
|
$
|
7.01
|
|
Crude Oil
|
|
Oct - Dec 2018
|
|
Basis Swaps
|
|
Magellan East Houston/Cushing
|
|
(6,000
|
)
|
|
$
|
6.38
|
|
Crude Oil
|
|
Oct - Dec 2018
|
|
Fixed Price Calls
|
|
WTI
|
|
(13,000
|
)
|
|
$
|
58.89
|
|
Crude Oil
|
|
2019
|
|
Fixed Price Swaps
|
|
WTI
|
|
(38,000
|
)
|
|
$
|
53.49
|
|
Crude Oil
|
|
2019
|
|
Basis Swaps
|
|
Midland/Cushing
|
|
(21,008
|
)
|
|
$
|
(1.16
|
)
|
Crude Oil
|
|
2019
|
|
Basis Swaps
|
|
Nymex CMA Roll
|
|
(20,000
|
)
|
|
$
|
0.11
|
|
Crude Oil
|
|
2019
|
|
Basis Swaps
|
|
Magellan East Houston/Midland
|
|
(838
|
)
|
|
$
|
8.50
|
|
Crude Oil
|
|
2019
|
|
Basis Swaps
|
|
Argus LLS/Midland
|
|
(838
|
)
|
|
$
|
8.60
|
|
Crude Oil
|
|
2019
|
|
Fixed Price Calls
|
|
WTI
|
|
(5,000
|
)
|
|
$
|
54.08
|
|
Crude Oil
|
|
2020
|
|
Basis Swaps
|
|
Midland/Cushing
|
|
(7,486
|
)
|
|
$
|
(1.31
|
)
|
Crude Oil
|
|
2020
|
|
Basis Swaps
|
|
Brent/WTI Spread
|
|
(3,000
|
)
|
|
$
|
8.40
|
|
Crude Oil
|
|
2021
|
|
Basis Swaps
|
|
Brent/WTI Spread
|
|
(1,000
|
)
|
|
$
|
8.00
|
|
Crude Oil
|
|
2022
|
|
Basis Swaps
|
|
Brent/WTI Spread
|
|
(1,000
|
)
|
|
$
|
7.75
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|||
Natural Gas
|
|
Oct - Dec 2018
|
|
Fixed Price Swaps
|
|
Henry Hub
|
|
(128
|
)
|
|
$
|
2.99
|
|
Natural Gas
|
|
Oct - Dec 2018
|
|
Basis Swaps
|
|
Permian
|
|
(48
|
)
|
|
$
|
(0.31
|
)
|
Natural Gas
|
|
Oct - Dec 2018
|
|
Basis Swaps
|
|
Waha
|
|
(15
|
)
|
|
$
|
0.93
|
|
Natural Gas
|
|
Oct - Dec 2018
|
|
Basis Swaps
|
|
Houston Ship Channel
|
|
(43
|
)
|
|
$
|
(0.08
|
)
|
Natural Gas
|
|
Oct - Dec 2018
|
|
Fixed Price Calls
|
|
Henry Hub
|
|
(15
|
)
|
|
$
|
4.75
|
|
Natural Gas
|
|
2019
|
|
Fixed Price Swaps
|
|
Henry Hub
|
|
(48
|
)
|
|
$
|
2.87
|
|
Natural Gas
|
|
2019
|
|
Basis Swaps
|
|
Permian
|
|
(25
|
)
|
|
$
|
(0.39
|
)
|
Natural Gas
|
|
2019
|
|
Basis Swaps
|
|
Waha
|
|
(15
|
)
|
|
$
|
2.94
|
|
Natural Gas
|
|
2019
|
|
Basis Swaps
|
|
Houston Ship Channel
|
|
(30
|
)
|
|
$
|
(0.09
|
)
|
Natural Gas
|
|
2020
|
|
Basis Swaps
|
|
Waha
|
|
(60
|
)
|
|
$
|
(0.79
|
)
|
Natural Gas
|
|
2021
|
|
Basis Swaps
|
|
Waha
|
|
(70
|
)
|
|
$
|
(0.59
|
)
|
Natural Gas
|
|
2022
|
|
Basis Swaps
|
|
Waha
|
|
(70
|
)
|
|
$
|
(0.57
|
)
|
Natural Gas
|
|
2023
|
|
Basis Swaps
|
|
Waha
|
|
(50
|
)
|
|
$
|
(0.52
|
)
|
Natural Gas Liquids
|
|
|
|
|
|
|
|
|
|
|
|||
Natural Gas Liquids
|
|
Oct - Dec 2018
|
|
Fixed Price Swaps
|
|
Ethane Mont Belvieu
|
|
(3,300
|
)
|
|
$
|
0.29
|
|
Natural Gas Liquids
|
|
Oct - Dec 2018
|
|
Fixed Price Swaps
|
|
Propane Conway
|
|
(900
|
)
|
|
$
|
0.79
|
|
Natural Gas Liquids
|
|
Oct - Dec 2018
|
|
Fixed Price Swaps
|
|
PropaneMont Belvieu
|
|
(3,900
|
)
|
|
$
|
0.80
|
|
Natural Gas Liquids
|
|
Oct - Dec 2018
|
|
Fixed Price Swaps
|
|
Iso Butane Mont Belvieu
|
|
(700
|
)
|
|
$
|
0.91
|
|
Natural Gas Liquids
|
|
Oct - Dec 2018
|
|
Fixed Price Swaps
|
|
Normal Butane Mont Belvieu
|
|
(1,800
|
)
|
|
$
|
0.90
|
|
Natural Gas Liquids
|
|
Oct - Dec 2018
|
|
Fixed Price Swaps
|
|
Natural Gasoline Mont Belvieu
|
|
(1,500
|
)
|
|
$
|
1.31
|
|
(a)
|
Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls or swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread. Derivatives related to natural gas liquids production are fixed price swaps.
|
(b)
|
Crude oil volumes are reported in Bbl/day, natural gas volumes are reported in BBtu/day and natural gas liquids volumes are reported in Bbl/day.
|
(c)
|
The weighted average price for crude oil is reported in $/Bbl, natural gas is reported in $/MMBtu and natural gas liquids is reported in $/Gal.
|
|
Gross Amount Presented on Balance Sheet
|
|
Netting Adjustments (a)
|
|
Net Amount
|
||||||
September 30, 2018
|
(Millions)
|
||||||||||
Derivative assets with right of offset or master netting agreements
|
$
|
120
|
|
|
$
|
(97
|
)
|
|
$
|
23
|
|
Derivative liabilities with right of offset or master netting agreements
|
$
|
(442
|
)
|
|
$
|
97
|
|
|
$
|
(345
|
)
|
|
|
|
|
|
|
||||||
December 31, 2017
|
|
|
|
|
|
||||||
Derivative assets with right of offset or master netting agreements
|
$
|
59
|
|
|
$
|
(42
|
)
|
|
$
|
17
|
|
Derivative liabilities with right of offset or master netting agreements
|
$
|
(236
|
)
|
|
$
|
42
|
|
|
$
|
(194
|
)
|
(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 and nine months ended September 30, 2018 and 2017
|
|
Three months
ended September 30, |
|
Nine months
ended September 30, |
||||||||||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||||||||||||||
Production Sales Volume Data(a):
|
|
|
Per day
|
|
|
|
Per day
|
|
|
|
Per day
|
|
|
|
Per day
|
||||||||||||
Oil (MBbls)
|
7,670
|
|
|
83.4
|
|
|
4,973
|
|
|
54.1
|
|
|
20,941
|
|
|
76.7
|
|
|
13,049
|
|
|
47.8
|
|
||||
Natural gas (MMcf)
|
14,759
|
|
|
160
|
|
|
7,946
|
|
|
86
|
|
|
40,522
|
|
|
148
|
|
|
24,050
|
|
|
88
|
|
||||
NGLs (MBbls)
|
1,259
|
|
|
13.7
|
|
|
829
|
|
|
9.0
|
|
|
4,313
|
|
|
15.8
|
|
|
2,494
|
|
|
9.1
|
|
||||
Combined equivalent volumes (MBoe)(b)
|
11,389
|
|
|
123.8
|
|
|
7,126
|
|
|
77.5
|
|
|
32,007
|
|
|
117.2
|
|
|
19,550
|
|
|
71.6
|
|
||||
Financial Data (millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Total product revenues
|
$
|
554
|
|
|
|
|
$
|
247
|
|
|
|
|
$
|
1,481
|
|
|
|
|
$
|
660
|
|
|
|
||||
Total revenues
|
$
|
484
|
|
|
|
|
$
|
145
|
|
|
|
|
$
|
1,288
|
|
|
|
|
$
|
890
|
|
|
|
||||
Operating income (loss)
|
$
|
26
|
|
|
|
|
$
|
(10
|
)
|
|
|
|
$
|
29
|
|
|
|
|
$
|
238
|
|
|
|
||||
Capital expenditure activity (c)
|
$
|
370
|
|
|
|
|
$
|
315
|
|
|
|
|
$
|
1,074
|
|
|
|
|
$
|
911
|
|
|
|
(a)
|
Excludes production from discontinued operations.
|
(b)
|
MBoe are calculated using the ratio of six Mcf to one barrel of oil.
|
(c)
|
Includes capital expenditures activity related to discontinued operations of $36 million for the three months ended September 30, 2017, and $27 million and $142 million for the nine months ended September 30, 2018 and 2017, respectively.
|
•
|
$307 million
increase in product revenues, primarily oil sales, of which $167 million related to higher oil prices and $118 million related to higher oil volumes.
|
•
|
the absence of $112 million net gain on sales of assets in 2017, see Note
4
of Notes to Consolidated Financial Statements;
|
•
|
$130 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income; and
|
•
|
$33 million unfavorable change in net loss on derivatives .
|
•
|
$575 million unfavorable change in net gain (loss) on derivatives;
|
•
|
$337 million higher operating costs including depreciation, depletion and amortization, lease and facility, gathering, processing and transportation, and taxes other than income; and
|
•
|
the absence of
$150 million
net gain on sales of assets recorded in 2017 (see Note
4
of Notes to Consolidated Financial Statements).
|
•
|
$821 million
increase in product revenues, primarily oil sales, of which $414 million related to higher oil prices and $346 million related to higher oil volumes; and
|
•
|
$15 million lower exploration expenses (see Note
4
of Notes to Consolidated Financial Statements).
|
•
|
value driven development of our positions in the Delaware and Williston Basins;
|
•
|
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;
|
•
|
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 September 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2018
|
|
2017
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Revenues:
|
|
|
|
|
|
|
|
|||||||
Oil sales
|
$
|
503
|
|
|
$
|
218
|
|
|
$
|
285
|
|
|
131
|
%
|
Natural gas sales
|
18
|
|
|
13
|
|
|
5
|
|
|
38
|
%
|
|||
Natural gas liquid sales
|
33
|
|
|
16
|
|
|
17
|
|
|
106
|
%
|
|||
Total product revenues
|
554
|
|
|
247
|
|
|
307
|
|
|
124
|
%
|
|||
Net gain (loss) on derivatives
|
(139
|
)
|
|
(106
|
)
|
|
(33
|
)
|
|
(31
|
)%
|
|||
Commodity management
|
68
|
|
|
4
|
|
|
64
|
|
|
NM
|
|
|||
Other
|
1
|
|
|
—
|
|
|
1
|
|
|
NM
|
|
|||
Total revenues
|
$
|
484
|
|
|
$
|
145
|
|
|
$
|
339
|
|
|
NM
|
|
•
|
$285 million
increase
in oil sales reflects $167 million related to higher sales prices and $118 million related to higher production sales volumes for the three months ended
September 30, 2018
compared to
2017
. The increase in production sales volumes was driven by both our Delaware and Williston Basins. The Delaware Basin volumes were 42.8 MBbls per day compared to 22.7 MBbls per day for the three months ended
September 30, 2018
and
2017
, respectively. The Williston Basin volumes were 40.6 MBbls per day compared to 31.3 MBbls per day for the three months ended
September 30, 2018
and
2017
, respectively. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for the three months ended
September 30, 2018
and
2017
:
|
|
Three months
ended September 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
||||||
Oil sales (per barrel)
|
65.52
|
|
|
$
|
43.74
|
|
|
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)
|
(11.09
|
)
|
|
2.03
|
|
||
Oil net price including derivative settlements (per barrel)
|
$
|
54.43
|
|
|
$
|
45.77
|
|
|
|
|
|
||||
Oil production sales volumes (MBbls)
|
7,670
|
|
|
4,973
|
|
||
Per day oil production sales volumes (MBbls/d)
|
83.4
|
|
|
54.1
|
|
•
|
$5 million
increase
in natural gas sales reflects $11 million related to higher production sales volumes offset by $6 million related to lower sales prices for the three months ended
September 30, 2018
compared to 2017. The increased production primarily relates to the Delaware Basin. The Delaware Basin volumes were 135 Mmcf per day compared to 74 Mmcf per day for the three months ended
September 30, 2018
and
2017
, respectively. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for the three months ended
September 30, 2018
and
2017
:
|
|
Three months
ended September 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
||||||
Natural gas sales (per Mcf)
|
$
|
1.22
|
|
|
$
|
1.67
|
|
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(a)
|
0.61
|
|
|
0.43
|
|
||
Natural gas net price including derivative settlements (per Mcf)
|
$
|
1.83
|
|
|
$
|
2.10
|
|
|
|
|
|
||||
Natural gas production sales volumes (MMcf)
|
14,759
|
|
|
7,946
|
|
||
Per day natural gas production sales volumes (MMcf/d)
|
160
|
|
|
86
|
|
•
|
$17 million
increase
in natural gas liquids sales primarily reflect $9 million related to higher sales price and $8 million related to higher production sales volumes for the three months ended
September 30, 2018
compared to 2017. The increased production primarily relates to the Delaware Basin. The Delaware Basin volumes were 10.0 MBbls per day compared to 6.6 MBbls per day for the three months ended
September 30, 2018
and
2017
, respectively. Startup operations on the first 200 MMcf per day cryogenic processing train at the new joint venture gas plant in the Stateline area of the Delaware Basin concluded in late September although the timing of the plant’s availability impacted third-quarter NGL volumes by about 4,000 bbl per day. WPX placed about half that amount (165,000 barrels) into storage with a majority to be sold in the fourth quarter of 2018. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for the three months ended
September 30, 2018
and
2017
:
|
|
Three months
ended September 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
||||||
NGL sales (per barrel)
|
$
|
26.68
|
|
|
$
|
19.28
|
|
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)
|
(7.09
|
)
|
|
—
|
|
||
NGL net price including derivative settlements (per barrel)
|
$
|
19.59
|
|
|
$
|
19.28
|
|
|
|
|
|
||||
NGL production sales volumes (MBbls)
|
1,259
|
|
|
829
|
|
||
Per day NGL production sales volumes (MBbls/d)
|
13.7
|
|
|
9.0
|
|
•
|
$33 million
unfavorable
change in net loss on derivatives primarily reflects unfavorable change in natural gas and natural gas liquids derivatives which was a result of losses in 2018 due to increases in 2018 of forward commodity prices relative to our hedge positions. Settlements to be paid on derivatives totaled
$85 million
and settlements to be received totaled
$14 million
for three months ended
September 30, 2018
and
September 30, 2017
, respectively.
|
•
|
$64 million
increase
in commodity management revenues is primarily due to higher crude sales volumes. A similar increase is reflected in the
$59 million
increase in related commodity management costs and expenses, discussed below. The increase in crude sales volumes is due to crude oil purchases and sales to fulfill certain sales commitments.
|
|
Three months
ended September 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|
Per Boe Expense
|
|||||||||||
|
2018
|
|
2017
|
|
|
2018
|
|
2017
|
||||||||||
|
(Millions)
|
|
|
|
|
|
|
|
|
|||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Depreciation, depletion and amortization
|
$
|
193
|
|
|
$
|
133
|
|
|
$
|
(60
|
)
|
|
(45
|
)%
|
|
$17.01
|
|
$18.72
|
Lease and facility operating
|
68
|
|
|
45
|
|
|
(23
|
)
|
|
(51
|
)%
|
|
$5.92
|
|
$6.29
|
|||
Gathering, processing and transportation
|
26
|
|
|
5
|
|
|
(21
|
)
|
|
NM
|
|
|
$2.29
|
|
$0.76
|
|||
Taxes other than income
|
45
|
|
|
19
|
|
|
(26
|
)
|
|
(137
|
)%
|
|
$3.96
|
|
$2.77
|
|||
Exploration
|
18
|
|
|
17
|
|
|
(1
|
)
|
|
(6
|
)%
|
|
|
|
|
|||
General and administrative:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
General and administrative expenses
|
36
|
|
|
33
|
|
|
(3
|
)
|
|
(9
|
)%
|
|
$3.17
|
|
$4.70
|
|||
Equity-based compensation
|
8
|
|
|
7
|
|
|
(1
|
)
|
|
(14
|
)%
|
|
$0.68
|
|
$0.92
|
|||
Total general and administrative
|
44
|
|
|
40
|
|
|
(4
|
)
|
|
(10
|
)%
|
|
$3.85
|
|
$5.62
|
|||
Commodity management
|
63
|
|
|
4
|
|
|
(59
|
)
|
|
NM
|
|
|
|
|
|
|||
Net gain—sales of assets
|
(1
|
)
|
|
(112
|
)
|
|
(111
|
)
|
|
(99
|
)%
|
|
|
|
|
|||
Other—net
|
2
|
|
|
4
|
|
|
2
|
|
|
50
|
%
|
|
|
|
|
|||
Total costs and expenses
|
$
|
458
|
|
|
$
|
155
|
|
|
$
|
(303
|
)
|
|
(195
|
)%
|
|
|
|
|
Operating income (loss)
|
$
|
26
|
|
|
$
|
(10
|
)
|
|
$
|
36
|
|
|
NM
|
|
|
|
|
|
•
|
$60 million
increase
in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $1.71 per Boe decrease in rate which was impacted by higher estimated proved reserves as compared to September 30, 2017 due to a higher 12-month average price, the addition of new wells with lower relative cost per Boe and an increase in Delaware production relative to the overall total.
|
•
|
$23 million
increase
in lease and facility operating expenses primarily related to increased production volumes and increased workovers in 2018 compared to 2017.
|
•
|
$21 million
increase
in gathering, processing and transportation primarily due in part to the adoption of ASU 2014-09,
Revenue from Contracts with Customers
, for which the net expense on certain transportation related arrangements that were recorded as a reduction in oil revenue in 2017 are included in gathering, processing and transportation in 2018 and growth in production volumes.
|
•
|
$26 million
increase
in taxes other than income related to increased product revenues, previously discussed.
|
•
|
$59 million
increase
in commodity management expenses is primarily due to higher crude purchase volumes. The increase in crude oil purchase volumes is due to crude oil purchases and sales to fulfill certain sales commitments.
|
•
|
$1 million gain on sale of assets in 2018 compared to $112 million gain on sale of assets in 2017. See Note
4
of Notes to Consolidated Financial Statements.
|
|
Three months
ended September 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2018
|
|
2017
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Operating income (loss)
|
$
|
26
|
|
|
$
|
(10
|
)
|
|
$
|
36
|
|
|
NM
|
|
Interest expense
|
(38
|
)
|
|
(48
|
)
|
|
10
|
|
|
21
|
%
|
|||
Loss on extinguishment of debt
|
—
|
|
|
(17
|
)
|
|
17
|
|
|
100
|
%
|
|||
Investment income and other
|
(2
|
)
|
|
2
|
|
|
(4
|
)
|
|
NM
|
|
|||
Loss from continuing operations before income taxes
|
(14
|
)
|
|
(73
|
)
|
|
59
|
|
|
81
|
%
|
|||
Provision (benefit) for income taxes
|
(8
|
)
|
|
305
|
|
|
313
|
|
|
NM
|
|
|||
Loss from continuing operations
|
(6
|
)
|
|
(378
|
)
|
|
372
|
|
|
98
|
%
|
|||
Income (loss) from discontinued operations
|
(1
|
)
|
|
232
|
|
|
(233
|
)
|
|
NM
|
|
|||
Net loss
|
$
|
(7
|
)
|
|
$
|
(146
|
)
|
|
139
|
|
|
95
|
%
|
|
Nine months
ended September 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2018
|
|
2017
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Revenues:
|
|
|
|
|
|
|
|
|||||||
Oil sales
|
$
|
1,331
|
|
|
$
|
571
|
|
|
$
|
760
|
|
|
133
|
%
|
Natural gas sales
|
51
|
|
|
46
|
|
|
5
|
|
|
11
|
%
|
|||
Natural gas liquid sales
|
99
|
|
|
43
|
|
|
56
|
|
|
130
|
%
|
|||
Total product revenues
|
1,481
|
|
|
660
|
|
|
821
|
|
|
124
|
%
|
|||
Net gain (loss) on derivatives
|
(362
|
)
|
|
213
|
|
|
(575
|
)
|
|
NM
|
|
|||
Commodity management
|
168
|
|
|
17
|
|
|
151
|
|
|
NM
|
|
|||
Other
|
1
|
|
|
—
|
|
|
1
|
|
|
NM
|
|
|||
Total revenues
|
$
|
1,288
|
|
|
$
|
890
|
|
|
$
|
398
|
|
|
45
|
%
|
•
|
$760 million
increase
in oil sales reflects $414 million related to higher sales prices and $346 million related to higher production sales volumes for the nine months ended
September 30, 2018
compared to
2017
. The Delaware Basin volumes were 38.6 MBbls per day compared to 18.8 MBbls per day for the
nine
months ended
September 30, 2018
and
2017
, respectively. The Williston Basin volumes were 38.1 MBbls per day compared to 29.0 MBbls per day for the
nine
months ended
September 30, 2018
and
2017
, respectively. The following table reflects oil production prices, the price impact of our derivative settlements and volumes for the
nine
months ended
September 30, 2018
and
2017
:
|
|
Nine months
ended September 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
||||||
Oil sales (per barrel)
|
$
|
63.55
|
|
|
$
|
43.78
|
|
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)
|
(10.89
|
)
|
|
1.43
|
|
||
Oil net price including derivative settlements (per barrel)
|
$
|
52.66
|
|
|
$
|
45.21
|
|
|
|
|
|
||||
Oil production sales volumes (MBbls)
|
20,941
|
|
|
13,049
|
|
||
Per day oil production sales volumes (MBbls/d)
|
76.7
|
|
|
47.8
|
|
•
|
$5 million
increase
in natural gas sales reflects $32 million in higher production sales volumes offset by $27 million related to lower sales prices for the nine months ended
September 30, 2018
compared to 2017. The increase in our production sales volumes primarily relates to our Delaware Basin which had production volumes of 125 MMcf per day compared to 69 MMcf per day for the nine months ended
September 30, 2018
compared to 2017, respectively. The following table reflects natural gas production prices, the price impact of our derivative settlements and volumes for the
nine
months ended
September 30, 2018
and
2017
:
|
|
Nine months
ended September 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
||||||
Natural gas sales (per Mcf)
|
$
|
1.25
|
|
|
$
|
1.91
|
|
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(a)
|
0.59
|
|
|
0.17
|
|
||
Natural gas net price including derivative settlements (per Mcf)
|
$
|
1.84
|
|
|
$
|
2.08
|
|
|
|
|
|
||||
Natural gas production sales volumes (MMcf)
|
40,522
|
|
|
24,050
|
|
||
Per day natural gas production sales volumes (MMcf/d)
|
148
|
|
|
88
|
|
•
|
$56 million
increase
in natural gas liquids sales primarily reflects $31 million related to higher production sales volumes and $25 million related to higher sales prices for the nine months ended
September 30, 2018
compared to 2017. The Delaware Basin volumes were 11.7 MBbls per day compared to 6.8 MBbls per day for the
nine
months ended
September 30, 2018
and
2017
, respectively. The Williston Basin volumes were 4.1 MBbls per day compared to 2.3 MBbls per day for the
nine
months ended
September 30, 2018
and
2017
, respectively. The following table reflects NGL production prices, the price impact of our derivative settlements and volumes for the
nine
months ended
September 30, 2018
and
2017
:
|
|
Nine months
ended September 30, |
||||||
|
2018
|
|
2017
|
||||
|
|
||||||
NGL sales (per barrel)
|
$
|
22.99
|
|
|
$
|
17.08
|
|
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)
|
(3.10
|
)
|
|
—
|
|
||
NGL net price including derivative settlements (per barrel)
|
$
|
19.89
|
|
|
$
|
17.08
|
|
|
|
|
|
||||
NGL production sales volumes (MBbls)
|
4,313
|
|
|
2,494
|
|
||
Per day NGL production sales volumes (MBbls/d)
|
15.8
|
|
|
9.1
|
|
•
|
$575 million
unfavorable
change in net gain (loss) on derivatives primarily reflects unfavorable change in crude oil derivatives which was a result of losses in 2018 due to increases in 2018 of forward commodity prices relative to our hedge positions as opposed to gains in 2017 due to decreases in 2017 of forward commodity prices relative to our hedge position at that time. Settlements to be paid on derivatives totaled
$218 million
for the nine months ended
September 30, 2018
and settlements to be received totaled
$23 million
for the nine months ended September 30, 2017.
|
•
|
$151 million
increase
in commodity management revenues primarily due to higher crude sales volumes. A similar increase is reflected in the $
139 million
increase in related commodity management costs and expenses, discussed below. The increase in crude sales volumes is due to crude oil purchases and sales to fulfill certain sales commitments.
|
|
Nine months
ended September 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|
Per Boe Expense
|
|||||||||||
|
2018
|
|
2017
|
|
|
2018
|
|
2017
|
||||||||||
|
(Millions)
|
|
|
|
|
|
|
|
|
|||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Depreciation, depletion and amortization
|
$
|
551
|
|
|
$
|
387
|
|
|
$
|
(164
|
)
|
|
(42
|
)%
|
|
$17.22
|
|
$19.80
|
Lease and facility operating
|
182
|
|
|
122
|
|
|
(60
|
)
|
|
(49
|
)%
|
|
$5.68
|
|
$6.24
|
|||
Gathering, processing and transportation
|
64
|
|
|
16
|
|
|
(48
|
)
|
|
NM
|
|
|
$2.01
|
|
$0.83
|
|||
Taxes other than income
|
116
|
|
|
51
|
|
|
(65
|
)
|
|
(127
|
)%
|
|
$3.64
|
|
$2.63
|
|||
Exploration
|
54
|
|
|
69
|
|
|
15
|
|
|
22
|
%
|
|
|
|
|
|||
General and administrative:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
General and administrative expenses
|
106
|
|
|
103
|
|
|
(3
|
)
|
|
(3
|
)%
|
|
$3.32
|
|
$5.27
|
|||
Equity-based compensation
|
25
|
|
|
22
|
|
|
(3
|
)
|
|
(14
|
)%
|
|
$0.77
|
|
$1.12
|
|||
Total general and administrative
|
131
|
|
|
125
|
|
|
(6
|
)
|
|
(5
|
)%
|
|
$4.09
|
|
$6.39
|
|||
Commodity management
|
156
|
|
|
17
|
|
|
(139
|
)
|
|
NM
|
|
|
|
|
|
|||
Net gain—sales of assets
|
(1
|
)
|
|
(150
|
)
|
|
(149
|
)
|
|
99
|
%
|
|
|
|
|
|||
Other—net
|
6
|
|
|
15
|
|
|
9
|
|
|
60
|
%
|
|
|
|
|
|||
Total costs and expenses
|
$
|
1,259
|
|
|
$
|
652
|
|
|
$
|
(607
|
)
|
|
(93
|
)%
|
|
|
|
|
Operating income
|
$
|
29
|
|
|
$
|
238
|
|
|
$
|
(209
|
)
|
|
(88
|
)%
|
|
|
|
|
•
|
$164 million
increase
in depreciation, depletion and amortization is primarily due to higher production volumes partially offset by a $2.58 per Boe decrease in rate which was impacted by higher estimated reserves as compared to September 30, 2017 due to a higher 12-month average price, the addition of new wells with lower relative cost per Boe and an increase in Delaware production relative to the overall total.
|
•
|
$60 million
increase
in lease and facility operating expenses primarily related to increased production volumes.
|
•
|
$48 million
increase in gathering, processing and transportation is due in part to the adoption of ASU 2014-09,
Revenue from Contracts with Customers
, for which the net expense on certain transportation related arrangements that were recorded as a reduction in oil revenue in 2017 are included in gathering, processing and transportation in 2018 and growth in production volumes.
|
•
|
$65 million
increase
in taxes other than income related to increased product revenues, previously discussed.
|
•
|
$15 million
decrease
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 Delaware Basin in excess of the accumulated amortization balance recorded during first-quarter 2017. See Note
4
of Notes to Consolidated Financial Statements.
|
•
|
$139 million
increase
in commodity management expenses is primarily due to higher crude purchase volumes. The increase in crude oil purchase volumes is due to crude oil purchases and sales to fulfill certain sales commitments.
|
•
|
$1 million net gain on sales of assets in 2018 compared to
$150 million
net gain on sales of assets recorded in 2017. See Note
4
of Notes to Consolidated Financial Statements.
|
|
Nine months
ended September 30, |
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2018
|
|
2017
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Operating income
|
$
|
29
|
|
|
$
|
238
|
|
|
$
|
(209
|
)
|
|
(88
|
)%
|
Interest expense
|
(123
|
)
|
|
(141
|
)
|
|
18
|
|
|
13
|
%
|
|||
Loss on extinguishment of debt
|
(71
|
)
|
|
(17
|
)
|
|
(54
|
)
|
|
(318
|
)%
|
|||
Investment income and other
|
(2
|
)
|
|
4
|
|
|
(6
|
)
|
|
NM
|
|
|||
Income (loss) from continuing operations before income taxes
|
(167
|
)
|
|
84
|
|
|
(251
|
)
|
|
NM
|
|
|||
Provision (benefit) for income taxes
|
(56
|
)
|
|
40
|
|
|
96
|
|
|
NM
|
|
|||
Income (loss) from continuing operations
|
(111
|
)
|
|
44
|
|
|
(155
|
)
|
|
NM
|
|
|||
Loss from discontinued operations
|
(92
|
)
|
|
(22
|
)
|
|
(70
|
)
|
|
NM
|
|
|||
Net income (loss)
|
$
|
(203
|
)
|
|
$
|
22
|
|
|
(225
|
)
|
|
NM
|
|
•
|
our planned capital expenditures for full-year 2018, excluding acquisitions, are estimated to be approximately $1.3 billion to $1.4 billion of which $1.2 billion to $1.25 billion relate to drilling and completions, including facilities. Additionally, we estimate between $70 million and $85 million for equity investments. As of
September 30, 2018
, we have incurred $905 million of drilling and completion capital expenditures including facilities (and excluding capital related to discontinued operations); and
|
•
|
we have hedged a portion of our anticipated 2018 oil and gas production as disclosed in Commodity Price Risk Management following this section.
|
•
|
lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices or inflation on operating costs;
|
•
|
lower than anticipated proceeds from asset sales;
|
•
|
significantly lower than expected capital expenditures could result in the loss of undeveloped leasehold;
|
•
|
reduced access to our credit facility pursuant to our financial covenants; and
|
•
|
higher than expected development costs, including the impact of inflation.
|
Crude Oil
|
Oct - Dec 2018
|
|
2019
|
||||||||||
|
Volume
(Bbls/d) |
|
Weighted Average
Price ($/Bbl) |
|
Volume
(Bbls/d) |
|
Weighted Average
Price ($/Bbl) |
||||||
Fixed Price Swaps—WTI
|
57,500
|
|
|
$
|
52.82
|
|
|
38,000
|
|
|
$
|
53.49
|
|
Fixed Price Calls—WTI
|
13,000
|
|
|
$
|
58.89
|
|
|
5,000
|
|
|
$
|
54.08
|
|
Basis swaps—Midland/Cushing
|
14,000
|
|
|
$
|
(0.77
|
)
|
|
21,008
|
|
|
$
|
(1.16
|
)
|
Basis swaps—Nymex Calendar Monthly Avg Roll
|
13,261
|
|
|
$
|
0.03
|
|
|
20,000
|
|
|
$
|
0.11
|
|
Basis swaps—Argus LLS/Cushing
|
5,000
|
|
|
$
|
7.01
|
|
|
—
|
|
|
$
|
—
|
|
Basis swaps—Magellan East Houston/Cushing
|
6,000
|
|
|
$
|
6.38
|
|
|
—
|
|
|
$
|
—
|
|
Basis swaps—Magellan East Houston/Midland
|
—
|
|
|
$
|
—
|
|
|
1,841
|
|
|
$
|
8.12
|
|
Basis swaps—Argus LLS/Midland
|
—
|
|
|
$
|
—
|
|
|
838
|
|
|
$
|
8.60
|
|
Natural Gas
|
Oct - Dec 2018
|
|
2019
|
||||||||||
|
Volume
(BBtu/d) |
|
Weighted Average
Price ($/MMBtu) |
|
Volume
(BBtu/d) |
|
Weighted Average
Price ($/MMBtu) |
||||||
Fixed Price Swaps—Henry Hub
|
128
|
|
|
$
|
2.99
|
|
|
48
|
|
|
$
|
2.87
|
|
Fixed Price Calls—Henry Hub
|
15
|
|
|
$
|
4.75
|
|
|
—
|
|
|
$
|
—
|
|
Basis swaps—Permian
|
48
|
|
|
$
|
(0.31
|
)
|
|
25
|
|
|
$
|
(0.39
|
)
|
Basis swaps—Waha
|
15
|
|
|
$
|
0.93
|
|
|
15
|
|
|
$
|
2.94
|
|
Basis swaps—Houston Ship Channel
|
43
|
|
|
$
|
(0.08
|
)
|
|
30
|
|
|
$
|
(0.09
|
)
|
Natural Gas Liquids
|
Oct - Dec 2018
|
|
2019
|
||||||||||
|
Volume
(Bbls/d) |
|
Weighted Average
Price ($/Gal) |
|
Volume
(Bbls/d) |
|
Weighted Average
Price ($/Gal) |
||||||
Fixed Price Swaps—Ethane Mont Belvieu
|
3,300
|
|
|
$
|
0.29
|
|
|
—
|
|
|
$
|
—
|
|
Fixed Price Swaps—Propane Conway
|
900
|
|
|
$
|
0.79
|
|
|
—
|
|
|
$
|
—
|
|
Fixed Price Swaps—Propane Mont Belvieu
|
3,900
|
|
|
$
|
0.80
|
|
|
—
|
|
|
$
|
—
|
|
Fixed Price Swaps—Iso Butane Mont Belvieu
|
700
|
|
|
$
|
0.91
|
|
|
—
|
|
|
$
|
—
|
|
Fixed Price Swaps—Normal Butane Mont Belvieu
|
1,800
|
|
|
$
|
0.90
|
|
|
—
|
|
|
$
|
—
|
|
Fixed Price Swaps—Natural Gasoline Mont Belvieu
|
1,500
|
|
|
$
|
1.31
|
|
|
—
|
|
|
$
|
—
|
|
|
Nine months
ended September 30, |
||||||
|
2018
|
|
2017
|
||||
|
(Millions)
|
||||||
Net cash provided by (used in):
|
|
|
|
||||
Operating activities
|
$
|
652
|
|
|
$
|
228
|
|
Investing activities
|
(403
|
)
|
|
(1,626
|
)
|
||
Financing activities
|
(400
|
)
|
|
914
|
|
||
Net decrease in cash and cash equivalents and restricted cash
|
$
|
(151
|
)
|
|
$
|
(484
|
)
|
|
|
Nine months
ended September 30, |
||||||
|
|
2018
|
|
2017
|
||||
|
|
|
||||||
Cash capital expenditures for drilling and completions:
|
|
|
|
|
||||
Continuing operations
|
|
$
|
905
|
|
|
$
|
560
|
|
Discontinued operations
|
|
26
|
|
|
130
|
|
||
Total
|
|
$
|
931
|
|
|
$
|
690
|
|
|
|
|
|
|
||||
Capital expenditures incurred for drilling and completions:
|
|
|
|
|
||||
Continuing operations
|
|
$
|
958
|
|
|
$
|
608
|
|
Discontinued operations
|
|
23
|
|
|
134
|
|
||
Total
|
|
$
|
981
|
|
|
$
|
742
|
|
|
|
|
|
|
||||
Land acquisitions
|
|
$
|
27
|
|
|
$
|
63
|
|
Exhibit No.
|
|
Description
|
|
|
|
|
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)
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
Third Supplemental Indenture, dated as of May 23, 2018, between WPX Energy, Inc. and the Bank of New York Mellon Trust Company, N.A. as trustee (incorporated by reference to Exhibit 4.1 to WPX Energy, Inc’s Current Report on Form 8-K filed with the SEC on May 23, 2018)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
WPX Energy, Inc. Amended 2011 Employee Stock Purchase Plan (incorporated herein by reference to Appendix B to WPX Energy, Inc.’s definitive proxy statement on Schedule 14A (File No. 001-35322) filed with the SEC on March 29, 2018) (1)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
Form of Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.14 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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)
|
|
|
|
|
|
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 16, 2016) (1)
|
|
|
|
|
|
Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and Tier One Executives (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, 2018) (1)
|
|
|
|
|
|
Amended and Restated WPX Energy Executive Severance Pay Plan (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, 2018) (1)
|
|
|
|
|
|
Purchase and Sale Agreement by and Among WPX Energy Production, LLC and Enduring Resources IV, LLC dated January 30, 2018 (incorporated by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 5, 2018)
|
|
|
|
|
|
WPX Energy, Inc. 2013 Incentive Plan, as amended (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 19, 2018)
|
|
|
|
|
|
Form of Amended and Restated Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers (incorporated by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 19, 2018)
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
|
|
Form of Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 19, 2018)
|
|
|
|
|
|
Second Amendment to the Second Amended and Restated Credit Agreement and First Amendment to Guaranty and Collateral Agreement dated April 17, 2018, by and among the Company and certain of its wholly-owned subsidiaries signatory thereto, Wells Fargo Bank, National Association, as lender, Swingline Lender and Administrative Agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on April 20, 2018)
|
|
|
|
|
|
Amendment No. 3 to the WPX Energy, Inc. 2013 Incentive Plan (incorporated by reference to Appendix A to WPX Energy, Inc.’s definitive proxy statement on Schedule 14A (File No. 001-35322) filed with the SEC on March 29, 2018)
|
|
|
|
|
|
Form of Amendment to Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.40 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018)(1)
|
|
|
|
|
31.1
*
|
|
Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
31.2
*
|
|
Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
32.1
*
|
|
Certification by the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
101.INS*
|
|
XBRL Instance Document
|
|
|
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema
|
|
|
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase
|
|
|
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase
|
|
|
|
101.LAB*
|
|
XBRL Taxonomy Extension Label Linkbase
|
|
|
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase
|
*
|
Filed herewith
|
**
|
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
|
(1)
|
Management contract or compensatory plan or arrangement
|
|
|
|
|
|
|
|
|
|
|
WPX Energy, Inc.
(Registrant)
|
||
|
|
|
|
|
By:
|
|
/s/ Stephen L. Faulkner
|
|
|
|
Stephen L. Faulkner
Controller
(Principal Accounting Officer)
|
1 Year WPX Energy Chart |
1 Month WPX Energy Chart |
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