WPX ENERGY, INC., 10-K filed on 2/26/2015
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2014
Feb. 24, 2015
Jun. 30, 2014
Document Documentand Entity Information [Abstract]
 
 
 
Document Type
10-K 
 
 
Amendment Flag
false 
 
 
Document Period End Date
Dec. 31, 2014 
 
 
Document Fiscal Year Focus
2014 
 
 
Document Fiscal Period Focus
FY 
 
 
Trading Symbol
WPX 
 
 
Entity Registrant Name
WPX ENERGY, INC. 
 
 
Entity Central Index Key
0001518832 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Common Stock, Shares Outstanding
 
203,877,415 
 
Entity Public Float
 
 
$ 4,832,711,197 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Current assets:
 
 
Cash and cash equivalents
$ 41 
$ 47 
Accounts receivable, net of allowance of $6 million and $7 million as of December 31, 2014 and 2013, respectively
459 
518 
Deferred income taxes
0 
49 
Derivative assets
498 
50 
Inventories
45 
66 
Margin deposits
27 
71 
Disposal Group, Including Discontinued Operation, Assets, Current
773 
92 
Other
26 
29 
Total current assets
1,869 
922 
Properties and equipment, net (successful efforts method of accounting)
6,842 
6,760 
Derivative assets
38 
7 
Other noncurrent assets
49 
740 
Total assets
8,798 
8,429 
Current liabilities:
 
 
Accounts payable
712 
634 
Accrued and other current liabilities
177 
167 
Disposal Group, Including Discontinued Operation, Liabilities, Current
132 
41 
Customer margin deposits payable
0 
55 
Deferred Tax Liabilities, Net, Current
151 
0 
Derivative liabilities
37 
110 
Total current liabilities
1,209 
1,007 
Deferred income taxes
621 
776 
Long-term Debt and Capital Lease Obligations
2,280 1
1,911 1
Derivative liabilities
5 
12 
Asset retirement obligations
198 
305 
Other noncurrent liabilities
57 
208 
Contingent liabilities and commitments (Note 9)
   
   
Stockholders’ equity:
 
 
Preferred stock (100 million shares authorized at $0.01 par value; no shares issued)
0 
0 
Common stock (2 billion shares authorized at $0.01 par value; 203.7 million shares issued at December 31, 2014 and 201 million shares issued at December 31, 2013)
2 
2 
Additional paid-in-capital
5,562 
5,516 
Accumulated deficit
(1,244)
(1,408)
Accumulated other comprehensive income (loss)
(1)
(1)
Total stockholders’ equity
4,319 
4,109 
Noncontrolling interests in consolidated subsidiaries
109 
101 
Total equity
4,428 
4,210 
Total liabilities and equity
$ 8,798 
$ 8,429 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 7 
$ 11 
Preferred stock, par value
$ 0.01 
$ 0.01 
Preferred stock, shares authorized
100,000,000 
100,000,000 
Preferred stock, shares issued
0 
0 
Common stock, par value
$ 0.01 
$ 0.01 
Common stock, shares authorized
2,000,000,000 
2,000,000,000 
Common stock, shares issued
203,700,000 
201,000,000 
Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Product revenues:
 
 
 
Natural gas sales
$ 1,002 
$ 896 
$ 1,193 
Oil and condensate sales
724 
534 
376 
Natural gas liquid sales
205 
228 
297 
Total product revenues
1,931 
1,658 
1,866 
Gas management
1,120 
891 
949 
Net gain (loss) on derivatives not designated as hedges (Note 14)
434 
(124)
78 
Other
8 
6 
7 
Total revenues
3,493 
2,431 
2,900 
Costs and expenses:
 
 
 
Lease and facility operating
244 
227 
202 
Gathering, processing and transportation
328 
350 
434 
Taxes other than income
126 
102 
68 
Gas management, including charges for unutilized pipeline capacity
987 
931 
996 
Exploration (Note 4)
173 
423 
71 
Depreciation, depletion and amortization
810 
858 
884 
Impairment of producing properties and costs of acquired unproved reserves
20 1
860 1
123 1
Loss On Sale Of Working Interests
196 
0 
0 
General and administrative
271 
269 
265 
Other—net
12 
12 
14 
Total costs and expenses
3,167 
4,032 
3,057 
Operating income (loss)
326 
(1,601)
(157)
Interest expense
(123)
(108)
(102)
Investment income, impairment of equity method investment and other
1 
(19)
1 
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest
204 
(1,728)
(258)
Provision (benefit) for income taxes
75 
(624)
(84)
Income (loss) from continuing operations
129 
(1,104)
(174)
Income (loss) from discontinued operations
42 
(87)
(37)
Net income (loss)
171 
(1,191)
(211)
Less: Net income (loss) attributable to noncontrolling interests
7 
(6)
12 
Net income (loss) attributable to WPX Energy, Inc.
164 
(1,185)
(223)
Income (Loss) from Continuing Operations Attributable to WPX
129 
(1,092)
(174)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX
$ 35 
$ (93)
$ (49)
Basic earnings (loss) per common share (Note 3):
 
 
 
Income (Loss) from Continuing Operations, Per Basic Share
$ 0.63 
$ (5.45)
$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share
$ 0.18 
$ (0.46)
$ (0.25)
Earnings Per Share, Basic
$ 0.81 
$ (5.91)
$ (1.12)
Basic weighted-average shares
202.7 
200.5 
198.8 
Income (Loss) from Continuing Operations, Per Diluted Share
$ 0.62 
$ (5.45)
$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share
$ 0.18 
$ (0.46)
$ (0.25)
Earnings Per Share, Diluted
$ 0.80 
$ (5.91)
$ (1.12)
Diluted weighted-average shares
206.3 
200.5 2
198.8 2
Consolidated Statements of Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Condensed Statement of Income Captions [Line Items]
 
 
 
Comprehensive income (loss) attributable to WPX Energy, Inc.
$ 164 
$ (1,188)
$ (440)
Other comprehensive income (loss):
 
 
 
Change in fair value of cash flow hedges, net of tax
0 1
0 1
57 1
Net reclassifications into earnings of net cash flow hedge gains, net of tax
0 2
(3)2
(274)2
Other comprehensive income (loss), net of tax
0 
(3)
(217)
Net income (loss) attributable to WPX Energy, Inc.
$ (164)
$ 1,185 
$ 223 
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Statement of Partners' Capital [Abstract]
 
 
Unrealized gains recognized for hedge transactions
 
$ 33 
Derivative Instruments Not Designated as Hedging Instruments, Gain
 
15 
Income tax provision for cash flow hedge gains
2 
159 
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)
$ 5 
$ 434 
Consolidated Statements of Changes in Equity (USD $)
In Millions, unless otherwise specified
Total
Total Stockholders’ Equity
Common Stock
Capital in Excess of Par Value
Accumulated Deficit
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Balance at beginning of period at Dec. 31, 2011
$ 5,759 
$ 5,678 
$ 2 
$ 5,457 
$ 0 
$ 219 
$ 81 1
Comprehensive income:
 
 
 
 
 
 
 
Net income (loss)
(211)
(223)
 
 
(223)
 
12 1
Other comprehensive income (loss)
(217)
(217)
 
 
 
(217)
 
Comprehensive income (loss)
(428)
 
 
 
 
 
 
Contribution from noncontrolling interest
10 
   
 
 
 
 
 
Contribution from noncontrolling interest1
 
 
 
 
 
 
10 
Stock based compensation, net of tax benefit
30 
30 
 
30 
 
 
 
Balance at end of period at Dec. 31, 2012
5,371 
5,268 
2 
5,487 
(223)
2 
103 1
Comprehensive income:
 
 
 
 
 
 
 
Net income (loss)
(1,191)
(1,185)
 
 
(1,185)
 
(6)1
Other comprehensive income (loss)
(3)
(3)
 
 
 
(3)
 
Comprehensive income (loss)
(1,194)
 
 
 
 
 
 
Contribution from noncontrolling interest
4 
 
 
 
 
 
4 1
Stock based compensation, net of tax benefit
29 
29 
 
29 
 
 
 
Balance at end of period at Dec. 31, 2013
4,210 
4,109 
2 
5,516 
(1,408)
(1)
101 1
Comprehensive income:
 
 
 
 
 
 
 
Net income (loss)
171 
164 
 
 
164 
 
7 1
Other comprehensive income (loss)
0 
0 
 
 
 
0 
 
Comprehensive income (loss)
171 
 
 
 
 
 
 
Contribution from noncontrolling interest
1 
 
 
 
 
 
1 1
Stock based compensation, net of tax benefit
46 
46 
 
46 
 
 
 
Balance at end of period at Dec. 31, 2014
$ 4,428 
$ 4,319 
$ 2 
$ 5,562 
$ (1,244)
$ (1)
$ 109 1
Consolidated Statements of Changes in Equity (Parenthetical)
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Noncontrolling interest, ownership percentage by noncontrolling owners
31.00% 
31.00% 
31.00% 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Operating Activities
 
 
 
Net income (loss)
$ 171 
$ (1,191)
$ (211)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
863 
940 
973 
Deferred income tax provision (benefit)
46 
(645)
(160)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments
236 
1,483 
288 
Amortization of stock-based awards
36 
32 
28 
Gain (loss) on sales of assets
(196)1
41 1
42 1
Cash provided (used) by operating assets and liabilities:
 
 
 
Accounts receivable
51 
(43)
68 
Inventories
19 
(5)
7 
Margin deposits and customer margin deposits payable
(10)
(18)
(5)
Other current assets
8 
(7)
7 
Accounts payable
4 
41 
(128)
Accrued and other current liabilities
(1)
(21)
12 
Changes in current and noncurrent derivative assets and liabilities
(559)
106 
(32)
Other, including changes in other noncurrent assets and liabilities
10 
5 
(9)
Net cash provided by operating activities
1,070 
636 
796 
Investing Activities
 
 
 
Capital expenditures
(1,807)2
(1,154)2
(1,521)2
Proceeds from sales of assets
374 
49 
310 
Other
(4)
(6)
7 
Net cash used in investing activities
(1,437)
(1,111)
(1,204)
Financing Activities
 
 
 
Proceeds from common stock
16 
6 
3 
Proceeds from long-term debt
500 
0 
6 
Borrowings on credit facility
1,947 
970 
50 
Payments on credit facility
(2,077)
(560)
(50)
Excess tax benefit of stock based awards
0 
0 
13 
Payments for long-term debt issuance costs
(13)
0 
0 
Other
(29)
10 
15 
Net cash provided by financing activities
344 
426 
37 
Net increase (decrease) in cash and cash equivalents
(23)
(49)
(371)
Effect of Exchange Rate on Cash and Cash Equivalents
(6)
(5)
(2)
Cash and cash equivalents at beginning of period
99 3
153 3
526 3
Cash and cash equivalents at end of period
$ 70 3
$ 99 3
$ 153 3
Consolidated Statements of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Loss On Sale Of Working Interests
$ 196 
$ 0 
$ 0 
Gain (Loss) on Disposition of Assets
 
 
38 
Gain on sale of Powder River Basin deep rights leasehold
 
36 
 
Increase to properties and equipment
(1,934)
(1,207)
(1,449)
Changes in related accounts payable and accounts receivable
127 
53 
(72)
Capital expenditures
$ (1,807)1
$ (1,154)1
$ (1,521)1
Discontinued Operations
Discontinued Operations
Discontinued Operations
On October 3, 2014, we announced an agreement to sell our international interests for approximately $294 million subject to the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco. During January 2015 we completed the divestiture of our 69 percent controlling equity interest in Apco and additional Argentina-related assets to Pluspetrol. Together, these non-operated international holding comprised our international segment. We expect to book a gain of approximately $40 million related to this transaction during first quarter 2015.
During the third quarter of 2014, our management signed an agreement to sell our remaining mature, coalbed methane holdings in the Powder River Basin for $155 million, subject to closing adjustments such as net revenues from effective date to closing date. We continue to negotiate the divestiture. The original sales agreement was scheduled to terminate February 13, 2015, but both parties agreed to extend the timetable. If the agreement does not successfully close in March, WPX has the option to terminate the transaction. Additionally, we have recorded a $45 million impairment of the net assets to a probability weighted-average of expected sales prices. The Company has not actively drilled in the basin since 2011. The Powder River operations have firm gathering and treating agreements with total commitments of $128 million through 2020. These commitments have been in excess of our production throughput. We also have certain pipeline capacity obligations held by our marketing company with total commitments for 2015 and beyond totaling $172 million. Depending on the final terms upon closing of the Powder River sale, we may record a portion of these obligations if they meet the definition of exit activities in association with exiting the Powder River Basin.
During the first quarter of 2012, our management signed an agreement to divest its holdings in the Barnett Shale and the Arkoma Basin. The transaction closed in second-quarter 2012. Total proceeds received from the sale were $306 million.
Summarized Results of Discontinued Operations
For the year ended December 31, 2014
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
189

 
$
163

 
$
352

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
41

 
$
37

 
$
78

Gathering, processing and transportation
70

 
1

 
71

Taxes other than income
16

 
28

 
44

Exploration
—

 
4

 
4

Depreciation, depletion and amortization
11

 
42

 
53

Impairment of assets held for sale
45

 
—

 
45

General and administrative
4

 
16

 
20

Other—net
—

 
12

 
12

Total costs and expenses
187

 
140

 
327

Operating income (loss)
2

 
23

 
25

Interest capitalized
1

 
—

 
1

Investment income and other
6

 
19

 
25

Income (loss) from discontinued operations before income taxes
9

 
42

 
51

Provision (benefit) for income taxes(a)
2

 
7

 
9

Income (loss) from discontinued operations
$
7

 
$
35

 
$
42


__________
(a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock.
For the year ended December 31, 2013
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
178

 
$
152

 
$
330

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
44

 
$
37

 
$
81

Gathering, processing and transportation
80

 
3

 
83

Taxes other than income
15

 
24

 
39

Exploration
1

 
7

 
8

Depreciation, depletion and amortization
48

 
34

 
82

Impairment of producing properties and costs of acquired unproved reserves
192

 
3

 
195

Gain on sale of Powder River Basin deep rights leasehold
(36
)
 
—

 
(36
)
General and administrative
6

 
14

 
20

Other—net
5

 
—

 
5

Total costs and expenses
355

 
122

 
477

Operating income (loss)
(177
)
 
30

 
(147
)
Interest capitalized
4

 
—

 
4

Investment income and other
4

 
21

 
25

Income (loss) from discontinued operations before income taxes
(169
)
 
51

 
(118
)
Provision (benefit) for income taxes(a)
(62
)
 
31

 
(31
)
Income (loss) from discontinued operations
$
(107
)
 
$
20

 
$
(87
)
__________
(a) International income tax provision for 2013 includes $10 million of deferred tax expense for the Argentina capital gains tax that was enacted in 2013.

For the year ended December 31, 2012
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
180

 
$
137

 
$
317

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
65

 
$
32

 
$
97

Gathering, processing and transportation
74

 
2

 
76

Taxes other than income
19

 
24

 
43

Gas management, including charges for unutilized pipeline capacity
1

 
—

 
1

Exploration
1

 
11

 
12

Depreciation, depletion and amortization
62

 
27

 
89

Impairment of producing properties and costs of acquired unproved reserves
102

 
—

 
102

Gain on sale of Barnett Shale and Arkoma Basin holdings
(38
)
 
—

 
(38
)
General and administrative
10

 
14

 
24

Other—net
(1
)
 
—

 
(1
)
Total costs and expenses
295

 
110

 
405

Operating income (loss)
(115
)
 
27

 
(88
)
Interest capitalized
6

 
—

 
6

Investment income and other
4

 
27

 
31

Income (loss) from discontinued operations before income taxes
(105
)
 
54

 
(51
)
Provision (benefit) for income taxes
(38
)
 
24

 
(14
)
Income (loss) from discontinued operations
$
(67
)
 
$
30

 
$
(37
)

Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations
December 31, 2014
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Assets classified as held for sale
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
—

 
$
29

 
$
29

Accounts receivable
—

 
25

 
25

Inventories
1

 
7

 
8

Other
—

 
14

 
14

Total current assets
1

 
75

 
76

Investments
18

 
134

 
152

Properties and equipment (successful efforts method of accounting)(a)
132

 
445

 
577

Less—accumulated depreciation, depletion and amortization
(10
)
 
(228
)
 
(238
)
Properties and equipment, net
122

 
217

 
339

Other noncurrent assets
—

 
6

 
6

Total assets classified as held for sale—discontinued operations
$
141

 
$
432

 
$
573

Total assets classified as held for sale—continuing operations (Note 4)
200

 
—

 
200

Total assets classified as held for sale on the Consolidated Balance Sheets
$
341

 
$
432

 
$
773

 
 
 
 
 
 
Liabilities associated with assets held for sale
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
—

 
$
34

 
$
34

Accrued and other current liabilities
3

 
23

 
26

Total current liabilities
3

 
57

 
60

Deferred income taxes
—

 
13

 
13

Long-term debt
—

 
2

 
2

Asset retirement obligations
45

 
7

 
52

Other noncurrent liabilities
—

 
3

 
3

Total liabilities associated with assets held for sale—discontinued operations
$
48

 
$
82

 
$
130

Total liabilities associated with assets held for sale—continuing operations (Note 4)
$
2

 
$
—

 
$
2

Total liabilities associated with assets held for sale on the Consolidated Balance Sheets
$
50

 
$
82

 
$
132

__________
(a) Domestic includes a $45 million impairment of the net assets of the Powder River Basin.

December 31, 2013
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Assets classified as held for sale
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
—

 
$
51

 
$
51

Accounts receivable
—

 
18

 
18

Inventories
1

 
5

 
6

Other
—

 
17

 
17

Total current assets
1

 
91

 
92

Investments
17

 
125

 
142

Properties and equipment (successful efforts method of accounting)
166

 
360

 
526

Less—accumulated depreciation, depletion and amortization
—

 
(194
)
 
(194
)
Properties and equipment, net
166

 
166

 
332

Total assets classified as held for sale—discontinued operations(a)
$
184

 
$
382

 
$
566

Total assets classified as held for sale—continuing operations (Note 4)(a)
148

 
—

 
148

Total assets classified as held for sale on the Consolidated Balance Sheets(a)
$
332

 
$
382

 
$
714

 
 
 
 
 
 
Liabilities associated with assets held for sale
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
—

 
$
18

 
$
18

Accrued and other current liabilities
3

 
20

 
23

Total current liabilities
3

 
38

 
41

Deferred income taxes
—

 
12

 
12

Long-term debt
—

 
5

 
5

Asset retirement obligations
47

 
4

 
51

Total liabilities associated with assets held for sale—discontinued operations(a)
$
50

 
$
59

 
$
109

Total liabilities associated with assets held for sale—continuing operations (Note 4)
2

 
—

 
2

Total liabilities associated with assets held for sale on the Consolidated Balance Sheets(a)
$
52

 
$
59

 
$
111

__________
(a) Noncurrent assets and liabilities as of December 31, 2013 that are attributable to discontinued operations have been reflected in other noncurrent assets and liabilities on the Consolidated Balance Sheet as of December 31, 2013.
Noncontrolling interests in consolidated subsidiaries of $109 million and $101 million as of December 31, 2014 and 2013, respectively, related to assets classified as held for sale.

Cash Flows Attributable to Discontinued Operations
Excluding taxes and changes to working capital related to Powder River Basin, total cash provided by operating activities related to discontinued operations was $65 million, $36 million and $18 million for 2014, 2013 and 2012, respectively. Total cash used in investing activities related to Powder River Basin discontinued operations was $11 million, $3 million and $20 million for 2014, 2013 and 2012, respectively. Cash provided by operating activities related to our international operations was $65 million, $56 million and $50 million for 2014, 2013 and 2012, respectively. Total cash used in investing activities related our international operations was $85 million, $43 million and $56 million for 2014, 2013 and 2012, respectively.
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
 The following table summarizes the calculation of earnings per share.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
$
129

 
$
(1,092
)
 
$
(174
)
Basic weighted-average shares
202.7

 
200.5

 
198.8

Effect of dilutive securities(a):
 
 
 
 
 
Nonvested restricted stock units and awards
2.7

 
 
 
 
Stock options
0.9

 
 
 
 
Diluted weighted-average shares
206.3

 
200.5

 
198.8

Earnings (loss) per common share from continuing operations:
 
 
 
 
 
Basic
$
0.63

 
$
(5.45
)
 
$
(0.87
)
Diluted
$
0.62

 
$
(5.45
)
 
$
(0.87
)

 __________
(a) For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.
The table below includes information related to stock options that were outstanding at December 31, 2014, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
 
 
 
 
 
 
 
2014
 
2013
 
2012
Options excluded (millions)
1.4

 
0.4

 
1.3

Weighted-average exercise price of options excluded
$
18.42

 
$
20.24

 
$
18.17

Exercise price range of options excluded
$16.46 - $21.81

 
$20.21  - $20.97

 
$16.46  - $20.97

Fourth quarter weighted-average market price
$
15.96

 
$
19.97

 
$
16.15

Asset Sales, Impairments and Exploration Expenses
Asset Sales, Impairments and Exploration Expenses
Asset Sales, Impairments and Exploration Expenses
In 2014, we recorded a total of $87 million in impairment charges associated with exploratory well costs and producing properties of which approximately $20 million is recorded as a separate line on the Consolidated Statements of Operations and $67 million is included in exploration expenses. In 2013, we recorded a total of $1.2 billion in impairment charges of which $860 million is recorded as a separate line on the Consolidated Statements of Operations, $317 million is included in exploration expenses and $20 million is included in investment income, impairment of equity method investment and other. These impairments are discussed further in the sections below.
Asset Sales
In June 2014, we sold portions of our working interests in certain Piceance Basin wells to Legacy Reserves LP (“Legacy”) for $325 million cash with an effective date of January 1, 2014. The terms of the sale also provided us with a 10 percent ownership in a newly created class of incentive distribution rights (“IDR”) of Legacy. The working interests represented approximately 300 Bcfe of proved reserves, or approximately 6 percent of WPX’s year-end 2013 proved reserves. Production related to these working interests for January 2014 through May 2014 approximated 70 MMcfe per day of our production. Based on an estimated total value received of $329 million, which represents estimated final cash proceeds and an estimated fair value of the IDRs, we recorded a $195 million loss on the sale in second quarter 2014. In the third quarter of 2014, we recorded an additional loss on sale of $1 million related to this transaction.
On December 3, 2014, we announced that we have agreed to sell our operations in northeast Pennsylvania and release certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $300 million in cash. Net property, plant and equipment related to this transaction, as of December 31,2014, was $200 million and asset retirement obligation liability was $2 million. The transaction includes physical operations covering approximately 46,700 acres, roughly 50 MMcfe per day of net natural gas production and 63 operated horizontal wells. The assets are primarily located in Susquehanna County, Pennsylvania. The transaction also includes the release of firm transportation capacity that we have under contract in the northeast, primarily 260 MMcfe per day with Millennium Pipeline. Upon the transfer of the firm capacity, we will be released from approximately $24 million per year in annual demand obligations associated with the transport. The transaction subsequently closed on January 30, 2015 and we estimate a net gain of at least $75 million will be recorded in first quarter 2015.
Impairments
The following table presents a summary of significant impairments of producing properties and costs of acquired unproved reserves and impairment of equity method investments.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Impairment of producing properties and costs of acquired unproved reserves(a)
$
20

 
$
860

 
$
123

Impairment of equity method investment in Appalachian Basin
$
—

 
$
20

 
$
—


 __________
(a)
Excludes related impairments of unproved leasehold included in exploration expenses.
As a result of declines in forward crude oil and natural gas prices primarily during the fourth-quarter 2014 as compared to forward prices as of December 31, 2013, we performed impairment assessments of our proved producing properties and costs of acquired unproved reserves. Accordingly, we recorded the following impairments during 2014:
•
$11 million impairment in the fourth quarter in the Green River Basin; and
•
$9 million of impairments in the fourth quarter of other properties.
As a result of declines in forward natural gas prices primarily during the fourth-quarter 2013 as compared to forward prices as of December 31, 2012, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves. Accordingly, we recorded the following impairments during 2013:
•
$772 million impairment in the fourth quarter of proved producing oil and gas properties in the Appalachian Basin; and
•
$88 million impairment in the Piceance Basin including impairments of capitalized costs of acquired unproved reserves of $19 million and $69 million in the third and fourth quarters, respectively, in the Kokopelli area.
The nature of the assets in the equity method investment in the Appalachian Basin is such that under normal circumstances an entity would capitalize and evaluate the assets as part of its producing properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing properties that utilize the assets of the entity. As a result of the 2013 impairment of the producing properties in the Appalachian Basin, we recorded an impairment of the equity method investment in 2013.
As a result of declines in forward natural gas and natural gas liquids prices during 2012 as compared to forward natural gas and natural gas liquids prices as of December 31, 2011, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves during 2012. Accordingly, we recorded the following impairments during 2012:
•
$75 million impairment of capitalized costs of acquired unproved reserves in the Piceance Basin; and
•
$48 million impairment of proved producing oil and gas properties in the Green River Basin.
Our impairment analyses included an assessment of undiscounted and discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (see Note 13).
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Geologic and geophysical costs
$
11

 
$
18

 
$
12

Impairments of exploratory area well costs and dry hole costs
88

 
3

 
1

Unproved leasehold property impairments, amortization and expiration
74

 
402

 
58

Total exploration expenses
$
173

 
$
423

 
$
71


Impairments of exploratory well and dry hole costs for 2014 include $67 million of impairment related to our Niobrara Shale well costs in the Piceance Basin and $16 million of impairments in other exploratory areas where management has determined to cease exploratory activities. The remaining amount represents dry hole costs associated with exploratory wells where hydrocarbons were not detected. The $67 million Niobrara Shale impairment relates to carrying costs on producing and science wells in excess of estimated discounted cash flows of the exploratory play. We continue to evaluate the potential of our Niobrara Shale exploratory play and plan to drill additional wells in 2015. As of December 31, 2014, our total domestic capitalized well costs associated with our exploratory areas, including the Niobrara Shale in the Piceance Basin, totaled approximately $37 million.
Unproved leasehold impairment, amortization and expiration in 2014 includes impairments of $41 million for unproved leasehold costs in exploratory areas where the company no longer intends to continue exploration activities.
Unproved leasehold impairment, amortization and expiration in 2013 includes a $317 million impairment to estimated fair values of Appalachia leasehold associated with our impairment of the producing properties in the Appalachian Basin.
Properties and Equipment
Properties and Equipment
Properties and Equipment 
Properties and equipment is carried at cost and consists of the following:
 
 
Estimated
Useful
Life(a)
(Years)
 
December 31,
 
2014
 
2013
 
 
 
(Millions)
Proved properties
(b)
 
$
10,386

 
$
10,955

Unproved properties
(c)
 
394

 
316

Gathering, processing and other facilities
15-25
 
251

 
209

Construction in progress
(c)
 
541

 
353

Other
3-40
 
181

 
178

Total properties and equipment, at cost
 
 
11,753

 
12,011

Accumulated depreciation, depletion and amortization
 
 
(4,911
)
 
(5,251
)
Properties and equipment—net
 
 
$
6,842

 
$
6,760

__________
(a)
Estimated useful lives are presented as of December 31, 2014.
(b)
Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
(c)
Unproved properties and construction in progress are not yet subject to depreciation and depletion.
During 2014, we purchased oil and natural gas properties in the San Juan Basin for $150 million. The properties purchased included both producing wells and undeveloped locations. Approximately $50 million of the purchase price was allocated to proved producing properties and the remainder to proved undeveloped or unproved leasehold within properties and equipment. The purchase is included within our capital expenditures on the Consolidated Statements of Cash Flows. 
Also during 2014, we closed an agreement to farmout a portion of our Trail Ridge properties in the Piceance Basin with TRDC LLC, a subsidiary of G2X Energy. We received $50 million in cash for 49 percent of our working interests in approximately 100 proved developed wells and certain incurred drilling costs. TRDC LLC has committed to a $170 million drilling carry on nearly 400 future wells and will make additional investments for its 49 percent working interest.
Unproved properties consist primarily of non-producing leasehold in the San Juan, Williston and Piceance Basins.
Asset Retirement Obligations 
Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.
A rollforward of our asset retirement obligations for the years ended 2014 and 2013 is presented below.
 
 
2014
 
2013
 
(Millions)
Balance, January 1
$
308

 
$
261

Liabilities incurred
19

 
11

Liabilities settled
(2
)
 
(1
)
Liabilities associated with assets sold
(65
)
 
—

Estimate revisions
(78
)
 
17

Accretion expense(a)
19

 
20

Balance, December 31
$
201

 
$
308

Amount reflected as current
$
3

 
$
3

__________
(a)
Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
Estimate revisions in 2014 are primarily associated with decreases in anticipated plug and abandonment costs.
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable
 
December 31,
 
2014
 
2013
 
(Millions)
Trade
$
215

 
$
208

Accrual for capital expenditures
313

 
225

Royalties
125

 
130

Cash overdrafts
—

 
35

Other
59

 
36

 
$
712

 
$
634


Accrued and other current liabilities
 
December 31,
 
2014
 
2013
 
(Millions)
Taxes other than income taxes
$
41

 
$
41

Accrued interest
53

 
43

Compensation and benefit related accruals
55

 
52

Other, including other loss contingencies
28

 
31

 
$
177

 
$
167

Debt and Banking Arrangements
Debt and Banking Arrangements
Debt and Banking Arrangements
As of the indicated dates, our debt consisted of the following:
 
 
December 31,
 
2014 (a)
 
2013 (a)
 
(Millions)
5.250% Senior Notes due 2017
$
400

 
$
400

6.000% Senior Notes due 2022
1,100

 
1,100

5.250% Senior Notes due 2024
500

 
—

Credit facility agreement
280

 
410

Other
1

 
2

Total debt
$
2,281

 
$
1,912

Less: Current portion of long-term debt
1

 
1

Total long-term debt
$
2,280

 
$
1,911

__________
(a)
Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.
Senior Notes
In November 2011, we issued $400 million aggregate principal amount of 5.25% Senior Notes due 2017 (the “2017 Notes”) and $1.1 billion aggregate principal amount of 6.00% Senior Notes due 2022 (the “2022 Notes”) pursuant to a private offering, and in June 2012 we exchanged these notes for registered 2017 Notes and 2022 Notes. The 2017 Notes and 2022 Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee.
In September 2014, we issued $500 million aggregate principal amount of 5.25% Senior Notes due 2024 (“the 2024 Notes”) pursuant to our automatic shelf registration statement on Form S-3 filed with the Securities and Exchange Commission. The 2024 Notes were issued under an indenture, as supplemented by a supplemental indenture, each between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the 2024 Notes were approximately $494 million after deducting the initial purchasers’ discounts and our offering expenses. The proceeds were used to repay borrowings under our Credit Facility.
The terms of the indentures governing our 2017 Notes, 2022 Notes and 2024 Notes are substantially identical.
Optional Redemption. We have the option prior to maturity for the 2017 Notes, prior to October 15, 2021 for the 2022 Notes, and prior to June 15, 2024 for the 2024 Notes to redeem some or all of such notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. We also have the option at any time or from time to time on or after October 15, 2021 to redeem the 2022 Notes, or on or after June 15, 2024, to redeem the 2024 Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date.
Change of Control. If we experience a change of control (as defined in the indentures governing the notes) accompanied by a specified rating decline, we must offer to repurchase the notes of such series at 101% of their principal amount, plus accrued and unpaid interest.
Covenants. The terms of the indentures governing our notes restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indentures also require us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indentures. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The indentures do not require the maintenance of any financial ratios or specified levels of net worth or liquidity.
Events of Default. Each of the following is an “Event of Default” under the indentures with respect to the notes of any series:
(1) a default in the payment of interest on the notes when due that continues for 30 days;
(2) a default in the payment of the principal of or any premium, if any, on the notes when due at their stated maturity, upon redemption, or otherwise;
(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting covenant under the indenture, which failure continues for a period of 90 days, after the date on which written notice of such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using commercially reasonable efforts to cure such failure; and
(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.
Credit Facility Agreement
In October 2014, we amended and restated our $1.5 billion five-year senior unsecured revolving credit facility agreement with Citibank, N.A., as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. The Credit Facility Agreement matures on October 28, 2019. As of December 31, 2014, the weighted average variable interest rate was 3.01% on the $280 million outstanding under the Credit Facility Agreement. As of February 25, 2015, we did not have any outstanding borrowings under the Credit Facility Agreement as proceeds from asset sales were used to repay all outstanding amounts.
Interest on borrowings under the Credit Facility Agreement are payable at rates per annum equal to, at our option: (1) a fluctuating base rate equal to the Alternate Base Rate plus the Applicable Rate, or (2) a periodic fixed rate equal to LIBOR plus the Applicable Rate. The Alternate Base Rate will be the highest of (i) the federal funds rate plus 0.5%, (ii) Citibank, N.A.'s publicly announced prime rate, and (iii) one-month LIBOR plus 1.0%. The Applicable Rate is defined in the Credit Facility Agreement and is determined by which interest rate we select and the ratings of our long-term unsecured debt. At December 31, 2014, the Applicable Rate was 1.875% on our LIBOR loans and 0.875% on our alternate base rate loans. Additionally, we will be required to pay a commitment fee, based on the ratings of our long-term unsecured debt, on the unused portion of the commitments under the Credit Facility Agreement. At December 31, 2014, the commitment fee rate was 0.30%.
Under the Credit Facility Agreement, when our long-term unsecured debt rating is not BBB- or better by S&P or Baa3 or better by Moody’s and the other of the two ratings is not less than BB+ by S&P or Ba1 by Moody's, we will be required to maintain a ratio of Consolidated Net Indebtedness (as defined in the Credit Facility Agreement) to Consolidated EBITDAX (as defined in the Credit Facility Agreement) of not greater than 3.75 to 1.00. Consolidated Net Indebtedness includes a reduction attributable to unrestricted cash and cash equivalents not to exceed $50 million. Consolidated EBITDAX will be calculated for the four fiscal quarters ending on the last day of any fiscal quarter for which financial statements have been or were required to be delivered. Additionally, the ratio of Consolidated Indebtedness (defined as Indebtedness of us and our consolidated subsidiaries determined on a consolidated basis) to Consolidated Total Capitalization (defined as Consolidated Indebtedness plus Consolidated Net Worth) will not be permitted to be greater than 60 percent and will be applicable for the life of the agreement.
When our long-term unsecured debt rating is BB or worse by S&P and Ba2 or worse by Moody's or BB- or worse by S&P or Ba3 or worse by Moody's, we will also be required to maintain a ratio of net present value of projected future cash flows from proved reserves, calculated in accordance with the terms of the Credit Facility Agreement, to Consolidated Indebtedness ratio of at least 1.25 to 1.00 for fiscal periods ending on or prior to December 31, 2015, and 1.50 to 1.00 for fiscal periods ending after December 31, 2015. Based on our current long-term unsecured debt ratings, as of the date of this filing, we are not required to comply with this covenant. In addition, this covenant will not apply at any time after the occurrence of the Investment Grade Date, which is the first date after closing on which our long-term unsecured debt is rated BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or watch by either agency), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.
The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of our subsidiaries to incur indebtedness; our and our subsidiaries' ability to grant certain liens, materially change the nature of our or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of our material subsidiaries to enter into certain restrictive agreements; our and our material subsidiaries' ability to enter into certain affiliate transactions; and our ability to merge or consolidate with any person or sell all or substantially all of our assets to any person. We and our subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to certain exceptions and/or standards of materiality applicable to the contracting parties that differ from those applicable to investors.
The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to us occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of any loans outstanding under the Credit Facility Agreement at the time, in addition to the exercise of other rights and remedies available.
Letters of Credit
WPX has also entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At December 31, 2014 a total of $320 million in letters of credit have been issued.
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
The provision (benefit) for income taxes from continuing operations includes:
 
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Provision (benefit):
 
 
 
 
 
Current:
 
 
 
 
 
Federal
$
(3
)
 
$
(29
)
 
$
49

State
1

 
1

 
4

 
(2
)
 
(28
)
 
53

Deferred:
 
 
 
 
 
Federal
76

 
(549
)
 
(125
)
State
1

 
(47
)
 
(12
)
 
77

 
(596
)
 
(137
)
Total provision (benefit)
$
75

 
$
(624
)
 
$
(84
)

 
Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Provision (benefit) at statutory rate
$
71

 
$
(604
)
 
$
(90
)
Increases (decreases) in taxes resulting from:
 
 
 
 
 
State income taxes (net of federal benefit)
3

 
(111
)
 
(6
)
State income tax change in valuation allowance (net of federal benefit)
(1
)
 
80

 
—

State income tax legislation change (net of federal benefit)
9

 
—

 
—

Effective state income tax rate change (net of federal benefit)
(9
)
 
(3
)
 
—

Alternative minimum tax credits
—

 
—

 
11

Other
2

 
14

 
1

Provision (benefit) for income taxes
$
75

 
$
(624
)
 
$
(84
)

Significant components of deferred tax liabilities and deferred tax assets are as follows:
 
December 31,
 
2014
 
2013
 
(Millions)
Deferred tax liabilities:
 
 
 
Properties and equipment
$
738

 
$
961

Derivatives, net
170

 
—

Other, net
17

 
23

Total deferred tax liabilities
925

 
984

Deferred tax assets:
 
 
 
Accrued liabilities and other
124

 
176

Alternative minimum tax credits
60

 
76

Loss carryovers
51

 
83

Derivatives, net
—

 
21

Other, net
32

 
—

Total deferred tax assets
267

 
356

Less: valuation allowance
114

 
99

Total net deferred tax assets
153

 
257

Net deferred tax liabilities
$
772

 
$
727


Net cash payments for domestic income taxes were $9 million and $40 million in 2014 and 2012, respectively, while net cash refunds were $26 million in 2013.
We had federal net operating loss (“NOL”) carryovers of approximately $114 million at December 31, 2013, which were fully utilized in 2014. The Company has state NOL carryovers, primarily in Pennsylvania, of approximately $875 million and $825 million at 2014 and 2013, respectively, of which more than 90 percent expire after 2029.
Tax reform legislation was enacted by the state of New York on March, 31, 2014, and had an impact on us as a result of our marketing activities in the state. As a result, we recorded an additional $9 million of deferred tax expense in the first quarter of 2014 to accrue for the impact of this new legislation. However, due to announced asset sales in fourth-quarter 2014, our state effective tax rate decreased resulting in a $9 million deferred tax benefit.
We have recorded valuation allowances against deferred tax assets attributable primarily to our operations in Pennsylvania. In addition, we have recorded a valuation allowance against a portion of the excess tax basis in our investment in Apco, which have been included in discontinued operations (see Note 2). In determining whether to record a valuation allowance we assess available positive and negative evidence to evaluate whether it is more likely than not that we will realize the benefit of a deferred tax asset. We have historically generated NOLs in Pennsylvania where we file separately, plus they have an annual limitation that impacts our ability to use NOL carryovers to reduce future taxable income in Pennsylvania. As a result of our assessment of available evidence, a valuation allowance was recorded to reduce recognized tax assets, net of federal tax, to an amount that will more likely than not be realized by the Company.
Employee share-based compensation attributable to the exercise of stock options and vesting of restricted stock is deductible by us for tax purposes. To the extent these tax deductions exceed the previously accrued deferred tax benefit for these items the excess tax benefit is not recognized under GAAP until the deduction reduces current taxes payable. At December 31, 2013, $7 million of excess tax benefit was not included in the Company’s loss carryovers deferred tax asset. The $7 million excess tax benefit was recognized in 2014 due to the utilization of loss carryovers.
Through the effective date of our spin-off from The Williams Companies, Inc. (“Williams”), December 31, 2011, our domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. Effective with the spin-off, we entered into a tax sharing agreement with Williams which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off. Pursuant to the tax sharing agreement, we remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. We are not aware of any significant adjustments related to our business, but the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments to 2011 unrelated to our business. Williams previously notified us of certain corrections that resulted in reductions in the alternative minimum tax credit allocated to us, of which $11 million was a reduction of a benefit for income taxes in 2012.
The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.
As of December 31, 2014, the Company has no significant unrecognized tax benefits. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of an unrecognized tax benefit.
Contingent Liabilities and Commitments
Contingent Liabilities and Commitments
Contingent Liabilities and Commitments
Royalty litigation
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs’ proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We have completed the accounting process under the standard and have obtained the court's approval. However, as we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law, we have appealed this matter to the Colorado Court of Appeals. Plaintiffs have now filed a second class action lawsuit in the District Court, Garfield County containing similar allegations but related to subsequent time periods. The parties have agreed to seek a stay of this new lawsuit pending resolution of the first lawsuit in the Colorado Court of Appeals.
In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs seek monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter has been removed to the United States District Court for New Mexico. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico, violation of the New Mexico Oil and Gas Proceeds Payment Act and seek declaratory judgment, accounting and injunction. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR’s predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From January 2008 through December 2014, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $113 million.
Environmental matters
The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Matters related to Williams’ former power business
In connection with the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications.
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order.
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion on the Western States Antitrust Litigation. The panel held that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims, reversing the summary judgment entered in favor of the defendants. The panel further held that the district court did not abuse its discretion in denying the plaintiffs’ motions for leave to amend complaints. The U.S. Supreme Court granted Defendants' writ of certiorari. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
At December 31, 2014, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
In connection with the separation from Williams, we have agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.
Summary
As of December 31, 2014 and December 31, 2013, the Company had accrued approximately $16 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
Commitments
As part of managing our commodity price risk, we utilize contracted pipeline capacity to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2014 are as follows:
 
 
(Millions)
2015
$
177

2016
162

2017
149

2018
138

2019
126

Thereafter
389

 
 

Total
$
1,141


Also, in conjunction with the closing of the Powder River sale and current terms therein, we may record certain pipeline capacity obligations held by our marketing company associated with our exiting the Powder River Basin. Our total commitments related to these pipeline agreements for 2015 and beyond total $172 million.
We also have certain commitments (including commitments to an equity investee), primarily for natural gas gathering and treating services, which total $305 million over approximately six years.
Excluded from the pipeline capacity and natural gas gathering and treating services commitments discussed above are commitments totaling $88 million and $43 million, respectively, which have been or are assumed to be assigned to the buyers of assets held for sale.
In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Shale) at market prices from the same third party. Purchases under the 12-year contract began in the first quarter of 2012. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.
Future minimum annual rentals under noncancelable operating leases as of December 31, 2014, are payable as follows:
 
(Millions)
2015
$
37

2016
32

2017
11

2018
7

2019
7

Thereafter
15

 
 
Total
$
109


Leases totaling $0.5 million associated with assets held for sale are excluded from the operating lease commitments discussed above.
Total rent expense, excluding amounts capitalized, was $27 million, $27 million and $19 million in 2014, 2013 and 2012, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.
Employee Benefit Plans
Employee Benefit Plans
Employee Benefit Plans
WPX has a defined contribution plan which matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution of equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $17 million, $16 million and $6 million for 2014, 2013 and 2012, respectively. Approximately $10 million and $11 million were included in accrued and other current liabilities at December 31, 2014 and December 31, 2013 respectively, related to the non-matching annual employer contribution.
Stock-Based Compensation
Stock-Based Compensation
Stock-Based Compensation
WPX Energy, Inc. 2013 Incentive Plan
We have an equity incentive plan (“2013 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2013 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. The number of shares of common stock authorized for issuance pursuant to all awards granted under the 2013 Incentive Plan is 19.8 million shares. The 2013 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2013 Incentive Plan.
The ESPP allows domestic employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. The first offering under the ESPP commenced on March 1, 2012 and ended on June 30, 2012. Subsequent offering periods are from January through June and from July through December. Employees purchased 124 thousand shares at an average price of $12.56 per share during 2014.
Employee stock-based awards
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.
Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at fair value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Total stock-based compensation expense reflected in general and administrative expense for the years ended December 31, 2014, 2013 and 2012 was $35 million, $31 million and $28 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2014 was $41 million. This amount is comprised of $1 million related to stock options and $40 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2014.
  
WPX Plan
Stock Options
Options
 
Weighted-
Average
Exercise
Price
 
Aggregate
Intrinsic
Value
 
(Millions)
 
 
 
(Millions)
Outstanding at December 31, 2013(a)
4.1

 
$
13.27

 
$
29

Granted
0.4

 
$
19.03

 
 
Exercised
(1.3
)
 
$
11.11

 
 
Forfeited
(0.1
)
 
$
15.39

 
 
Outstanding at December 31, 2014(a)
3.1

 
$
14.80

 
$
2

Exercisable at December 31, 2014
2.7

 
$
14.26

 
$
2

__________
(a)
Includes approximately 137 thousand shares held by Williams’ employees at a weighted average price of $10.64 per share at December 31, 2014 and 344 thousand shares held by Williams' employees at a weighted average price of $9.24 per share at December 31, 2013.
The total intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was $13 million, $5 million and $5 million, respectively.
The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2014.
 
WPX Plan
 
Stock Options Outstanding
 
Stock Options Exercisable
Range of Exercise Prices
Options
 
Weighted-
Average
Exercise
Price
 
Weighted-
Average
Remaining
Contractual
Life
 
Options
 
Weighted-
Average
Exercise
Price
 
Weighted-
Average
Remaining
Contractual
Life
 
(Millions)
 
 
 
(Years)
 
(Millions)
 
 
 
(Years)
$ 6.02 to $10.68
0.5

 
$
7.59

 
2.8
 
0.5

 
$
7.59

 
2.8
$ 11.32 to $13.46
0.6

 
$
11.82

 
4.0
 
0.6

 
$
11.82

 
4.0
$14.41 to $18.23
1.5

 
$
16.39

 
6.1
 
1.2

 
$
16.36

 
5.6
$19.95 to $21.81
0.5

 
$
20.61

 
5.0
 
0.4

 
$
20.24

 
3.2
Total
3.1

 
$
14.80

 
5.0
 
2.7

 
$
14.26

 
4.4

The estimated fair value at date of grant of options for our common stock in each respective year, using the Black-Scholes option pricing model, is as follows:
 
WPX Plan
 
2014
 
2013
 
2012
Weighted-average grant date fair value of options granted
$
18.94

 
$
6.04

 
$
7.79

Weighted-average assumptions:
 
 
 
 
 
Dividend yield
—

 
—

 
—

Volatility
43.0
%
 
42.8
%
 
43.8
%
Risk-free interest rate
1.85
%
 
1.06
%
 
1.17
%
Expected life (years)
5.9

 
6.0

 
6.0


For 2014, 2013 and 2012, we determined that the Williams stock option grant data was not relevant for valuing WPX options; therefore the Company used the SEC simplified method. The expected volatility is based primarily on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life is assumed based on the SEC simplified method.
Cash received from stock option exercises was $14 million, $4 million and $2 million during 2014, 2013 and 2012, respectively.
Nonvested Restricted Stock Units
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2014.
 
WPX Plan
Restricted Stock Units
Shares
 
Weighted-
Average
Fair Value(a)
 
(Millions)
 
 
Nonvested at December 31, 2013
5.2

 
$
16.97

Granted
2.5

 
$
18.37

Forfeited
(0.7
)
 
$
16.92

Vested
(1.9
)
 
$
16.92

Nonvested at December 31, 2014
5.1

 
$
17.58

__________
(a)
Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.
Other restricted stock unit information
 
WPX Plan
 
2014
 
2013
 
2012
Weighted-average grant date fair value of restricted stock units granted during the year, per share
$
18.37

 
$
14.97

 
$
17.35

Total fair value of restricted stock units vested during the year (millions)
$
33

 
$
18

 
$
14


Performance-based shares granted represent 15 percent of nonvested restricted stock units outstanding at December 31, 2014. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.
Stockholders' Equity
Stockholders' Equity
Stockholders’ Equity
Common Stock
Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends were declared or paid for 2014, 2013 or 2012. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
Preferred Stock
Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding.
Fair Value Measurements
Fair Value Measurements
Fair Value Measurements
Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
•
Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.
•
Level 2—Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps and options. These options, which hedge future sales of production, are structured as costless collars or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings.
•
Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, and margin deposits and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
December 31, 2014
 
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
(Millions)
 
 
 
(Millions)
Energy derivative assets
$
14

 
$
517

 
$
5

 
$
536

 
$
30

 
$
26

 
$
1

 
$
57

Energy derivative liabilities
$
32

 
$
10

 
$
—

 
$
42

 
$
83

 
$
38

 
$
1

 
$
122

Total debt(a)
$
—

 
$
2,218

 
$
—

 
$
2,218

 
$
—

 
$
1,938

 
$
—

 
$
1,938

__________
(a)
The carrying value of total debt, excluding capital leases, was $2,280 million and $1,910 million as of December 31, 2014 and 2013, respectively.
Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Forward, swap and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with 100 percent of the net fair value of our derivatives portfolio expiring in the next 24 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at December 31, 2014, consist primarily of natural gas index transactions that are used to manage our physical requirements.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the years ended December 31, 2014 or 2013.
The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
 
Years ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Beginning balance
$
—

 
$
(1
)
 
$
1

Realized and unrealized gains (losses):
 
 
 
 
 
Included in income (loss) from continuing operations
5

 
(2
)
 
3

Included in other comprehensive income (loss)
—

 
—

 
—

Purchases, issuances, and settlements
—

 
3

 
(5
)
Transfers out of Level 3
—

 
—

 
—

Ending balance
$
5

 
$
—

 
$
(1
)
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31
$
5

 
$
(1
)
 
$
(1
)

Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Consolidated Statements of Operations.
As previously noted, we evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. On several occasions in the past three years, we considered the significant declines in forward natural gas, oil and NGL prices as compared to the previous respective period’s forward prices to be indicators of a potential impairment. As a result, we assessed the carrying value of our producing properties and costs of acquired unproved reserves for impairments as of the dates of those declines. Our assessments utilized estimates of future cash flows, including in some instances potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of proved, probable and possible reserve quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational basis differentials), expectation for market participant drilling plans, expected capital costs and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. In each of the three years ended December 31, 2014, our assessments identified certain properties with a carrying value in excess of their calculated fair values and as a result, we recorded impairment charges. The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
 
Total losses for
the years ended December 31,
 
 
 
2014 (a)
 
 
 
2013 (b)
 
 
 
2012 (c)
 
 
 
(Millions)
 
 
Impairments:
 
 
 
 
 
 
 
 
 
 
 
Producing properties and costs of acquired unproved reserves (Note 2 and Note 4)
$
20

 
 
 
$
1,055

 
 
 
$
225

 
 
Unproved leasehold
—

 
 
 
317

 
 
 
—

 
 
Equity method investment (Note 4)
—

 
 
 
20

 
 
 
—

 
 
 
$
20

 
 
 
$
1,392

 
  
 
$
225

 
  
__________
(a)
As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:
•
$11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.
•
$9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties.

(b)
As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:
•
$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
•
$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.
•
$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
•
$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
•
$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

(c)
As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:
•
$102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
•
$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
Derivatives and Concentration of Credit Risk
Derivatives and Concentration of Credit Risk
Derivatives and Concentration of Credit Risk
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas, oil and natural gas liquids attributable to commodity price risk. Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we entered into commodity derivative contracts that continued to serve as economic hedges but were not designated as cash flow hedges for accounting purposes as we elected not to utilize this method of accounting on new derivatives instruments. Remaining commodity derivatives recorded at December 31, 2011 that were designated as cash flow hedges were fully realized by the end of the first quarter of 2013.
We produce, buy and sell natural gas, crude oil and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas, crude oil and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions.
We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation and storage contracts economically hedge the expected cash flows generated by those agreements.
Derivatives related to production
The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of December 31, 2014.
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
2015
 
Fixed Price Swaps
 
Henry Hub
 
(442
)
 
$
4.10

Natural Gas
 
2015
 
Costless Collars
 
Henry Hub
 
(50
)
 
$ 4.00 - 4.50
Natural Gas
 
2015
 
Basis Swaps
 
NGPL
 
(13
)
 
$
(0.16
)
Natural Gas
 
2015
 
Basis Swaps
 
Rockies
 
(150
)
 
$
(0.11
)
Natural Gas
 
2015
 
Basis Swaps
 
San Juan
 
(85
)
 
$
(0.10
)
Natural Gas
 
2015
 
Basis Swaps
 
SoCal
 
(20
)
 
$
0.18

Natural Gas
 
2016
 
Fixed Price Swaps
 
Henry Hub
 
(200
)
 
$
3.98

Natural Gas
 
2016
 
Swaptions
 
Henry Hub
 
(90
)
 
$
4.23

Natural Gas
 
2017
 
Swaptions
 
Henry Hub
 
(65
)
 
$
4.19

Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
2015
 
Fixed Price Swaps
 
WTI
 
(20,236
)
 
$
94.88

Crude Oil
 
2015
 
Swaptions
 
WTI
 
(882
)
 
$
97.29

Crude Oil
 
2016
 
Swaptions
 
WTI
 
(5,250
)
 
$
97.55

 
__________
(a)
Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.
(b)
Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.
(c)
The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.

Derivatives primarily related to transportation
    
The following table sets forth the derivative notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, which are included in our commodity derivatives portfolio as of December 31, 2014. The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.
 
Commodity
 
Period
 
Contract Type (a)
 
Location (b)
 
Notional Volume (c)
 
Natural Gas
 
2015
 
Basis Swaps
 
Multiple
 
(3
)
 
Natural Gas
 
2015
 
Index
 
Multiple
 
(118
)
 
Natural Gas
 
2016
 
Index
 
Multiple
 
(70
)
 
Natural Gas
 
2017
 
Index
 
Multiple
 
(70
)
 
Natural Gas
 
2018+
 
Index
 
Multiple
 
(379
)
 
__________
(a)
We enter into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.
(b)
We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.
(c)
Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
Fair values and gains (losses)
The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.
 
December 31,
 
2014
 
2013
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production not designated as hedging instruments
$
517

 
$
10

 
$
26

 
$
39

Derivatives related to physical marketing agreements not designated as hedging instruments
19

 
32

 
31

 
83

Total derivatives not designated as hedging instruments
$
536

 
$
42

 
$
57

 
$
122


 
The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.
 
Years Ended
December 31,
 
Classification
 
2014
 
2013
 
2012
 
 
 
 
(Millions)
Net gain recognized in other comprehensive income (loss) (effective portion)
$
—

 
$
—

 
$
90

 
AOCI
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)
$
—

 
$
5

 
$
434

 
Revenues
__________
(a)
Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.
There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.
The following table presents the net gain (loss) related to our energy commodity derivatives.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
 
Gain (loss) from derivatives related to production not designated as hedging instruments (a)
$
515

 
$
(57
)
 
$
66

Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)
(81
)
 
(67
)
 
12

Net gain (loss) on derivatives not designated as hedges
$
434

 
$
(124
)
 
$
78

__________
(a)
Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.
(b)
Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.
The cash flow impact of our derivative activities is presented in the Consolidated Statements of Cash Flows as changes in current and noncurrent derivative assets and liabilities.

Offsetting of derivative assets and liabilities
The following table presents our gross and net derivative assets and liabilities.
 
Gross Amount Presented on Balance Sheet
 
Netting Adjustments (a)
 
Cash Collateral Posted(Received)
 
Net Amount
December 31, 2014
(Millions)
Derivative assets with right of offset or master netting agreements
$
536

 
$
(25
)
 
$
—

 
$
511

Derivative liabilities with right of offset or master netting agreements
$
(42
)
 
$
25

 
$
17

 
$
—

 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
57

 
$
(50
)
 
$
—

 
$
7

Derivative liabilities with right of offset or master netting agreements
$
(122
)
 
$
50

 
$
52

 
$
(20
)
__________
(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.
Credit-risk-related features
Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from S&P’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.
As of December 31, 2014, we had collateral totaling $26 million posted to derivative counterparties, which includes $9 million of initial margin to clearinghouses or exchanges to enter into positions and $17 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $17 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2013, we had collateral totaling $71 million posted to derivative counterparties, which includes $19 million of initial margin to clearinghouses or exchanges to enter into positions and $52 million of maintenance margin for changes in fair value of those positions, to support the aggregate fair value of our net $72 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which included a reduction of less than $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was less than $1 million at December 31, 2014 and $20 million at December 31, 2013.
Cash flow hedges
Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During the first quarter of 2012, approximately $15 million of unrealized gains were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett Shale properties. The $15 million gain is included in net gains (losses) on derivatives not designated as hedges on the Consolidated Statements of Operations for 2012, as are second-quarter 2012 changes in forward mark-to-market value. As of December 31, 2012, we had hedged portions of future cash flows associated with anticipated energy commodity sales for three months. Based on recorded values at December 31, 2012, $3 million of net gains (net of income tax provision of $2 million) were expected to be reclassified into earnings in the first quarter of 2013. These recorded values are based on market prices of the commodities as of December 31, 2012. Actual gains or losses realized in the first quarter of 2013 matched these values. These gains substantially offset net losses that were realized in earnings from previous unfavorable market movements associated with underlying hedged transactions.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Accounts receivable
The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31:
 
2014
 
2013
 
(Millions)
Receivables by product or service:
 
 
 
Sale of natural gas, crude and related products and services
$
340

 
$
339

Joint interest owners
106

 
168

Other
13

 
11

Total
$
459

 
$
518


Natural gas customers include pipelines, distribution companies, producers, marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and North Dakota. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2014, 2013 and 2012, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.
The gross and net credit exposure from our derivative contracts as of December 31, 2014, is summarized as follows:
Counterparty Type
Gross Total
 
Net Total
 
(Millions)
Gas and electric utilities, integrated oil and gas companies, and other
$
4

 
$
4

Financial institutions (Investment Grade) (a)
533

 
508

 
537

 
512

Credit reserves
(1
)
 
(1
)
Credit exposure from derivatives
$
536

 
$
511

__________
(a)
We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.
Our nine largest net counterparty positions represent approximately 96 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.
Other
At December 31, 2014, we held collateral support of approximately $32 million, either in the form of cash or letters of credit, related to our gas management sale agreements.
The customer margin deposits payable as of December 31, 2014 related to our commodity agreements. Collateral support for our commodity agreements could also include letters of credit and guarantees of payment by credit worthy parties.
Revenues
During 2014, 2013 and 2012, BP Energy Company, a domestic segment customer, accounted for 13 percent, 16 percent and 11 percent of our consolidated revenues, respectively. During 2014 and 2013, Southern California Gas Company accounted for 8 percent and 11 percent of our consolidated revenues, respectively. Williams accounted for 14 percent of our consolidated revenue for 2012. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.
Quarterly Financial Data
QUARTERLY FINANCIAL DATA
WPX Energy, Inc.
QUARTERLY FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows:
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
(Millions, except per-share amounts)
2014
 
Revenues
$
894

 
$
727

 
$
747

 
$
1,125

Operating costs and expenses
$
783

 
$
659

 
$
570

 
$
656

 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
—

 
$
(144
)
 
$
46

 
$
227

Income (loss) from discontinued operations
19

 
11

 
20

 
(8
)
Net income (loss)
$
19

 
$
(133
)
 
$
66

 
$
219

Amounts attributable to WPX Energy, Inc.:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
—

 
$
(144
)
 
$
46

 
$
227

   Income (loss) from discontinued operations
18

 
9

 
16

 
(8
)
Net income (loss)
$
18

 
$
(135
)
 
$
62

 
$
219

Basic earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
—

 
$
(0.71
)
 
$
0.23

 
$
1.11

   Income (loss) from discontinued operations
0.09

 
0.05

 
0.07

 
(0.03
)
Net income (loss)
$
0.09

 
$
(0.66
)
 
$
0.30

 
$
1.08

Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
—

 
$
(0.71
)
 
$
0.23

 
$
1.10

   Income (loss) from discontinued operations
0.09

 
0.05

 
0.07

 
(0.04
)
Net income (loss)
$
0.09

 
$
(0.66
)
 
$
0.30

 
$
1.06

2013
 
 
 
 
 
 
 
Revenues
$
552

 
$
722

 
$
581

 
$
576

Operating costs and expenses
$
634

 
$
612

 
$
621

 
$
1,024

 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(115
)
 
$
6

 
$
(105
)
 
$
(890
)
Income (loss) from discontinued operations
2

 
16

 
(11
)
 
(94
)
Net income (loss)
$
(113
)
 
$
22

 
$
(116
)
 
$
(984
)
Amounts attributable to WPX Energy, Inc.:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(115
)
 
$
6

 
$
(105
)
 
$
(878
)
   Income (loss) from discontinued operations
(1
)
 
12

 
(9
)
 
(95
)
Net income (loss)
$
(116
)
 
$
18

 
$
(114
)
 
$
(973
)
Basic and diluted earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(0.57
)
 
$
0.03

 
$
(0.52
)
 
$
(4.37
)
   Income (loss) from discontinued operations
(0.01
)
 
0.06

 
(0.05
)
 
(0.48
)
Net income (loss)
$
(0.58
)
 
$
0.09

 
$
(0.57
)
 
$
(4.85
)

The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.
Net loss for fourth-quarter 2014 includes the following pre-tax items:
•
$87 million of impairments of costs of producing properties, acquired unproved reserves and leasehold (see Note 4).
•
During 2014, we assigned our remaining natural gas storage capacity agreement to a third party and sold the remaining natural gas stored under this agreement for a total loss of approximately $18 million reflected in gas management expenses in the Consolidated Statements of Operations.
Net income for third-quarter 2014 includes the following pre-tax items:
•
$22 million exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities.
Net loss for second-quarter 2014 includes the following pre-tax items:
•
$195 million loss on the sale of a portion of our working interests in certain Piceance Basin wells.
•
$40 million exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities.
•
$11 million increase in gas management expense related to a tariff rate refund received in prior years which is no longer under appeal by the pipeline company.
Net income for first-quarter 2014 includes the following pre-tax items:
•
$9 million deferred tax expense to accrue for the impact of new legislation (see Note 8.)
Net loss for fourth-quarter 2013 includes the following pre-tax items:
•
$1,178 million of impairments of costs of producing properties, acquired unproved reserves, leasehold and equity method investment (see Note 4).
•
$9 million buyout of a transportation agreement.
Net loss for third-quarter 2013 includes the following pre-tax items:
•
$19 million of impairments of costs of acquired unproved reserves in the Kokopelli area of the Piceance Basin (see Note 4).
Summarized quarterly financial data has been retrospectively adjusted to reflect the historical operating results for the Powder River Basin and our international segment as discontinued operations. (See Note 2 of Notes to Consolidated Financial Statements.) The increases (decreases) to amounts previously reported in our Form 10-Q were as follows:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter (a)
 
Fourth
Quarter
 
(Millions, except per-share amounts)
 
(Increase, (Decrease))
2014
 
Revenues
$
(93
)
 
$
(87
)
 
$
47

 
N/A

Operating costs and expenses
$
(62
)
 
$
62

 
$
31

 
N/A

 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(19
)
 
$
(11
)
 
$
(15
)
 
N/A

Income (loss) from discontinued operations
19

 
11

 
15

 
N/A

Net income (loss)
$
—

 
$
—

 
$
—

 
N/A

Amounts attributable to WPX Energy, Inc.:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(18
)
 
$
(9
)
 
$
(16
)
 
N/A

   Income (loss) from discontinued operations
18

 
9

 
16

 
N/A

Net income (loss)
$
—

 
$
—

 
$
—

 
N/A

Basic earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(0.09
)
 
$
(0.05
)
 
$
(0.05
)
 
N/A

   Income (loss) from discontinued operations
0.09

 
0.05

 
0.05

 
N/A

Net income (loss)
$
—

 
$
—

 
$
—

 
N/A

Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(0.09
)
 
$
(0.05
)
 
$
(0.05
)
 
N/A

   Income (loss) from discontinued operations
0.09

 
0.05

 
0.05

 
N/A

Net income (loss)
$
—

 
$
—

 
$
—

 
N/A

2013
 
 
 
 
 
 
 
Revenues
$
(79
)
 
$
(93
)
 
$
35

 
$
(81
)
Operating costs and expenses
$
(76
)
 
$
(77
)
 
$
22

 
$
(74
)
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(2
)
 
$
(16
)
 
$
3

 
$
94

Income (loss) from discontinued operations
2

 
16

 
(3
)
 
(94
)
Net income (loss)
$
—

 
$
—

 
$
—

 
$
—

Amounts attributable to WPX Energy, Inc.:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
1

 
$
(12
)
 
$
9

 
$
95

   Income (loss) from discontinued operations
(1
)
 
12

 
(9
)
 
(95
)
Net income (loss)
$
—

 
$
—

 
$
—

 
$
—

Basic and diluted earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
0.01

 
$
(0.06
)
 
$
0.01

 
$
0.48

   Income (loss) from discontinued operations
(0.01
)
 
0.06

 
(0.01
)
 
(0.48
)
Net income (loss)
$
—

 
$
—

 
$
—

 
$
—

__________
(a)
Third quarter only represents changes related to international being reported as discontinued operations because we reported Powder River Basin operations as discontinued in the third-quarter 2014.
Supplemental Oil and Gas Disclosures
Supplemental Oil and Gas Disclosures
We have significant continuing oil and gas producing activities primarily in the Piceance and San Juan Basins in the Rocky Mountain region and the Williston Basin in North Dakota, all of which are located in the United States. Until January 2015, we had international oil and gas producing activities, primarily in Argentina which were previously reported as a segment. The international activities were held for sale as of December 31, 2014 and as such, our international results of operations were reported as discontinued operations (see Note 2 of Notes to Consolidated Financial Statements). International net proved reserves, including amounts related to an equity method investment, were approximately 213 Bcfe or less than 5 percent of our total domestic and international reserves at December 31, 2014. Other than noted below, the following information relates to our domestic oil and gas activities and excludes our gas management activities.
With the exception of Capitalized Costs and the Results of Operations for all years presented, the following information includes information for the Powder River Basin and, through the date of sale in 2012, the holdings in the Barnett Shale and Arkoma Basin both of which have been reported as discontinued operations in our consolidated financial statements. The Powder River Basin operations represent less than 5 percent of our total domestic proved reserves at December 31, 2014. Additionally, capitalized costs exclude amounts related to assets in our Appalachian Basin which were held for sale as of December 31, 2014. Our Appalachian Basin assets held for sale represented less than 5 percent of our total domestic proved reserves.
Capitalized Costs
 
As of December 31,
 
2014
 
2013
 
(Millions)
Proved Properties
$
10,717

 
$
11,132

Unproved properties
394

 
324

 
11,111

 
11,456

Accumulated depreciation, depletion and amortization and valuation provisions
(4,698
)
 
(5,070
)
Net capitalized costs
$
6,413

 
$
6,386


•
Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $385 million and $328 million, net, for 2014 and 2013, respectively.
•
Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.
•
Unproved properties consist primarily of unproved leasehold costs.

Cost Incurred
 
 
For the years ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Acquisition
$
294

 
$
57

 
$
111

Exploration
92

 
104

 
23

Development
1,376

 
939

 
1,130

 
$
1,762

 
$
1,100

 
$
1,264



•
Costs incurred include capitalized and expensed items.
•
Acquisition costs are as follows: Costs in 2014 primarily relate to purchases of oil acreage in the San Juan Basin and include 28 Bcfe of proved reserves. The 2013 and 2012 costs are primarily for undeveloped leasehold in exploratory areas targeting oil reserves.
•
Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds.
•
Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins.
Results of Operations
 
For the years ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Revenues:
 
 
 
 
 
Natural gas sales
$
1,002

 
$
896

 
$
1,193

Oil and condensate sales
724

 
534

 
376

Natural gas liquid sales
205

 
228

 
297

Net gain (loss) on derivatives not designated as hedges
515

 
(57
)
 
66

Other revenues
8

 
6

 
7

Total revenues
2,454

 
1,607

 
1,939

Costs:
 
 
 
 
 
Lease and facility operating
244

 
227

 
202

Gathering, processing and transportation
328

 
350

 
434

Taxes other than income
126

 
102

 
68

Exploration
173

 
423

 
71

Depreciation, depletion and amortization
810

 
858

 
884

Impairment of certain proved properties
15

 
772

 
48

Impairment of costs of acquired unproved reserves
5

 
88

 
75

Loss on sale of working interests in the Piceance Basin
196

 
—

 
—

General and administrative
264

 
262

 
259

Other (income) expense
12

 
12

 
16

Total costs
2,173

 
3,094

 
2,057

Results of operations
281

 
(1,487
)
 
(118
)
Provision (benefit) for income taxes
103

 
(543
)
 
(43
)
Exploration and production net income (loss)
$
178

 
$
(944
)
 
$
(75
)

•
Amounts for all years exclude the equity losses from our equity method investees. Net equity losses from these investees were $1 million, $21 million and $1 million in 2014, 2013 and 2012, respectively.
•
Natural gas revenues consist of natural gas production sold and 2012 includes realized gains (losses) of derivatives that were designated as cash flow hedges.
•
For derivative instruments that were entered into after January 1, 2012, we did not designate those as cash flow hedges. Any gain (loss) related to these derivatives is included in net gain on derivatives not designated as hedges.
•
Other revenues consist of activities that are an indirect part of the producing activities.
•
Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes and the cost of retaining undeveloped leaseholds including lease amortization and impairments. Additionally, exploration costs in 2014 include impairments of certain exploratory well costs (see Note 4 of Notes to Consolidated Financial Statements). Exploration costs in 2013 include a $317 million impairment to estimated fair value of unproved leasehold costs in the Appalachian Basin.
•
Depreciation, depletion and amortization includes depreciation of support equipment.
 Proved Reserves
The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.
The following is a summary of changes in our domestic proved reserves including proved reserves in the Powder River Basin which is reported as discontinued operations. Proved reserves related to Powder River were approximately 200 Bcfe, 244.6 Bcfe and 235.9 Bcfe at December 31, 2014, 2013 and 2012, respectively. Excluded from the table are our international reserves that are primarily attributable to a consolidated subsidiary (Apco) which represented less than five percent of our total reserves. The international interests were sold in January 2015.
 
Natural Gas (Bcf)
 
Oil (MMBbls)
 
NGLs (MMBbls)
 
All Products (Bcfe)
Proved reserves at December 31, 2011
3,982.9

 
47.1

 
134.0

 
5,070.1

Revisions
(404.8
)
 
5.6

 
(21.1
)
 
(498.6
)
Purchases
5.8

 
—

 
—

 
5.8

Divestitures
(217.0
)
 
(0.3
)
 
(1.0
)
 
(224.8
)
Extensions and discoveries
409.2

 
28.5

 
8.9

 
633.8

Production
(407.0
)
 
(4.4
)
 
(10.4
)
 
(495.8
)
Proved reserves at December 31, 2012
3,369.1

 
76.5

 
110.4

 
4,490.5

Revisions
308.3

 
3.5

 
(25.4
)
 
177.2

Divestitures
(0.2
)
 
—

 
—

 
(0.5
)
Extensions and discoveries
312.0

 
28.8

 
8.1

 
533.8

Production
(359.4
)
 
(5.9
)
 
(7.4
)
 
(439.4
)
Proved reserves at December 31, 2013
3,629.8

 
102.9

 
85.7

 
4,761.6

Revisions
(198.3
)
 
(7.7
)
 
(13.4
)
 
(324.8
)
Purchases
6.0

 
4.2

 
0.8

 
36.5

Divestitures
(314.6
)
 
(1.8
)
 
(8.5
)
 
(376.6
)
Extensions and discoveries
362.1

 
42.4

 
12.5

 
691.3

Production
(335.4
)
 
(9.2
)
 
(6.3
)
 
(428.4
)
Proved reserves at December 31, 2014
3,149.6

 
130.8

 
70.8

 
4,359.6

 
 
 
 
 
 
 
 
Proved developed reserves:
 
 
 
 
 
 
 
December 31, 2012
2,170.7

 
23.7

 
64.9

 
2,702.6

December 31, 2013
2,265.2

 
36.8

 
48.6

 
2,777.7

December 31, 2014
2,090.0

 
60.0

 
43.9

 
2,713.8

 
 
 
 
 
 
 
 
Proved undeveloped reserves:
 
 
 
 
 
 
 
December 31, 2012
1,198.4

 
52.8

 
45.5

 
1,787.9

December 31, 2013
1,364.6

 
66.1

 
37.1

 
1,983.9

December 31, 2014
1,059.6

 
70.8

 
26.9

 
1,645.8

__________
(a)
Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.
•
Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.
•
Revisions in 2014 primarily reflect 97 Bcfe of net positive revisions to developed reserves and 422 Bcfe of net negative revisions to undeveloped reserves. The 422 Bcfe of net negative revisions were primarily due to a reduction in near-term drilling capital estimates and the related limitations imposed by the SEC five year rules. Revisions in 2013 reflects 133 Bcfe related to developed reserves and 44 Bcfe related to undeveloped reserves. Revisions in 2012 primarily resulted from the lower 12-month average price as compared to the 12-month average price used in 2011.
•
Divestitures in 2014 primarily relate to the sale of working interests in the Piceance Basin (See Note 4 of Notes to Consolidated Financial Statements). Divestitures in 2012 primarily relate to the sale of our holdings in the Barnett Shale and the Arkoma Basin (see Note 2 of Notes to Consolidated Financial Statements).
•
Extensions and discoveries in 2014 reflect 189 Bcfe added for drilled locations and 502 Bcfe added for new proved undeveloped locations. Extensions and discoveries in 2013 reflects 127 Bcfe added for drilled locations and 407 Bcfe added for new undeveloped locations. The 2014 and 2013 extensions and discoveries were primarily in the Piceance Basin, Williston Basin, Appalachian Basin and San Juan Basin. Extensions and discoveries in 2012 reflect 225 Bcfe added for drilled locations and 405 Bcfe added for new undeveloped locations. The 2012 extensions and discoveries were primarily in the Williston Basin, Appalachian Basin and Piceance Basin.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is based on the estimated quantities of proved reserves. Prices are based on the 12-month average price computed as an unweighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. For the years ended December 31, 2014, 2013 and 2012, the average domestic combined natural gas and NGL equivalent price was $4.34, $3.63 and $3.01 per Mcfe, respectively. The average domestic oil price used in the estimates for the years ended December 31, 2014, 2013 and 2012 was $83.62, $92.16 and $82.32 per barrel, respectively. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.
Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
Standardized Measure of Discounted Future Net Cash Flows
 
As of December 31,
 
2014
 
2013
 
(Millions)
Future cash inflows
$
26,444

 
$
24,547

Less:
 
 
 
Future production costs
12,641

 
12,148

Future development costs
3,426

 
3,789

Future income tax provisions
2,519

 
2,147

Future net cash flows
7,858

 
6,463

Less 10 percent annual discount for estimated timing of cash flows
3,975

 
3,499

Standardized measure of discounted future net cash inflows
$
3,883

 
$
2,964

 
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows
 
For the years ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Beginning of year
$
2,964

 
$
1,949

 
$
3,591

Sales of oil and gas produced, net of operating costs
(1,324
)
 
(1,040
)
 
(778
)
Net change in prices and production costs
303

 
1,198

 
(3,601
)
Extensions, discoveries and improved recovery, less estimated future costs
1,761

 
1,282

 
1,154

Development costs incurred during year
592

 
414

 
333

Changes in estimated future development costs
143

 
(736
)
 
50

Purchase of reserves in place, less estimated future costs
147

 
—

 
4

Sale of reserves in place, less estimated future costs
(391
)
 
(3
)
 
(272
)
Revisions of previous quantity estimates
(536
)
 
239

 
(232
)
Accretion of discount
383

 
225

 
481

Net change in income taxes
(142
)
 
(540
)
 
1,194

Other
(17
)
 
(24
)
 
25

Net changes
919

 
1,015

 
(1,642
)
End of year
$
3,883

 
$
2,964

 
$
1,949

Schedule II - Valuation And Qualifying Accounts
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
WPX Energy, Inc.
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
 
 
Beginning
Balance
 
Charged
(Credited)
to Costs and
Expenses
 
Other
 
Deductions
 
Ending
Balance
 
 
2014:
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts—accounts and notes receivable(a)
$
7

 
$
—

 
$
—

 
$
(1
)
 
$
6

Deferred tax asset valuation allowance(b)
102

 
(1
)
 
17

 
—

 
118

Price-risk management credit reserves—assets(a)(c)
—

 
—

 
1

 
—

 
1

2013:
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts—accounts and notes receivable(a)
11

 
(3
)
 
—

 
(1
)
 
7

Deferred tax asset valuation allowance(b)
19

 
80

 
3

 
—

 
102

2012:
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts—accounts and notes receivable(a)
13

 
(2
)
 
—

 
—

 
11

Deferred tax asset valuation allowance(b)
16

 
3

 
—

 
—

 
19

 __________
(a)
Deducted from related assets.
(b)
Deducted from related assets, with a portion included in assets held for sale.
(c)
Included in revenues.
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies 
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
Description of Business
Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.
In addition, we have operations in the Powder River Basin in Wyoming and, until January 29, 2015, had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia. As of December 31, 2014, the results of Powder River Basin and Apco are reported as discontinued operations.
The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we,” “us” or “our.”
Basis of Presentation
These financial statements are prepared on a consolidated basis.
Our continuing operations are comprised of a single business segment, the domestic development, production and gas management activities of natural gas, oil and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.
Discontinued operations
On January 29, 2015, we announced that we had completed the disposition of our international interests for approximately $294 million upon the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco in fourth-quarter 2014. The results of operations of our international segment have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.
During the third quarter of 2014, we signed an agreement for the sale of our remaining mature, coalbed methane holdings in the Powder River Basin in Wyoming. The results of operations of the Powder River Basin have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.
Also included in discontinued operations through the completion date of sale in second-quarter 2012, are the results of operations of the Barnett Shale and Arkoma Basin operations.
Additionally, see Note 9 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).
See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
Recently Issued Accounting Standards
In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows.
In August 2014, the FASB issued ASU No. 2014‑15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions which impact these financials include:
•
impairment assessments of long-lived assets;
•
valuations of derivatives;
•
estimation of natural gas and oil reserves;
•
assessments of litigation-related contingencies; and
•
asset retirement obligations.
 
These estimates are discussed further throughout these notes.
Cash and cash equivalents
Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash
Restricted cash consists of approximately $6 million and $21 million at December 31, 2014 and 2013, respectively, and is included in other current assets on the Consolidated Balance Sheets. Restricted cash in 2013 primarily related to escrow accounts established as part of the settlement agreement with certain California utilities, which was settled in 2014.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories
All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. The following table presents a summary of inventories.
 
Years ended December 31,
 
2014
 
2013
 
(Millions)
Material, supplies and other
$
43

 
$
43

Crude oil production in transit
2

 
10

Natural gas in underground storage
—

 
13

 
$
45

 
$
66


During 2014, we assigned our remaining natural gas storage capacity agreement to a third party resulting in a loss of approximately $14 million and sold the remaining natural gas stored under this agreement for a loss of approximately $4 million reflected in gas management expenses in the Consolidated Statements of Operations. We recognized lower of cost or market writedowns on natural gas in storage of $1 million in both 2014 and 2013 and $11 million in 2012.
Properties and equipment
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves related to our discontinued operations and are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.
Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations.
Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization
Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
Impairment of long-lived assets
We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.
Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities
Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities
Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
 
Derivative Treatment
  
Accounting Method
 
Normal purchases and normal sales exception
  
Accrual accounting
 
Designated in a qualifying hedging relationship
  
Hedge accounting
 
All other derivatives
  
Mark-to-market accounting
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be, or is no longer expected to be, highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
•
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;
•
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to gas management and for which we have not elected the normal purchases and normal sales exception;
•
the ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
•
realized gains and losses on all derivatives that settle financially;
•
realized gains and losses on derivatives held for trading purposes; and
•
realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product revenues
Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2014 and 2013 was insignificant. Additionally, natural gas revenues include $5 million and $423 million in 2013 and 2012, respectively, of realized gains from derivatives designated as cash flow hedges of our production sold.
Gas management revenues and expenses
Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas, oil and NGLs purchased from working interest owners in operated wells and other area third-party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
Charges for unutilized transportation capacity included in gas management expenses were $57 million, $61 million and $46 million in 2014, 2013 and 2012, respectively.
Capitalization of interest
We capitalize interest during construction on projects with construction periods of at least three months and a total estimated project cost in excess of $1 million. We use the weighted average rate of our outstanding debt (see Note 7).
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years.
Employee stock-based compensation
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Foreign exchange
Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 3).
Description of Business 
Description of Business
Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.
In addition, we have operations in the Powder River Basin in Wyoming and, until January 29, 2015, had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia. As of December 31, 2014, the results of Powder River Basin and Apco are reported as discontinued operations.
The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we,” “us” or “our.”
Basis of Presentation 
Basis of Presentation
These financial statements are prepared on a consolidated basis.
Our continuing operations are comprised of a single business segment, the domestic development, production and gas management activities of natural gas, oil and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.
Discontinued operations 
Discontinued operations
On January 29, 2015, we announced that we had completed the disposition of our international interests for approximately $294 million upon the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco in fourth-quarter 2014. The results of operations of our international segment have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.
During the third quarter of 2014, we signed an agreement for the sale of our remaining mature, coalbed methane holdings in the Powder River Basin in Wyoming. The results of operations of the Powder River Basin have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.
Also included in discontinued operations through the completion date of sale in second-quarter 2012, are the results of operations of the Barnett Shale and Arkoma Basin operations.
Additionally, see Note 9 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).
See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
New Accounting Pronouncements, Policy [Policy Text Block] 
Recently Issued Accounting Standards
In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows.
In August 2014, the FASB issued ASU No. 2014‑15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.
Principles of consolidation 
Principles of consolidation
The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
Use of estimates 
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions which impact these financials include:
•
impairment assessments of long-lived assets;
•
valuations of derivatives;
•
estimation of natural gas and oil reserves;
•
assessments of litigation-related contingencies; and
•
asset retirement obligations.
 
These estimates are discussed further throughout these notes.
Cash and cash equivalents 
Cash and cash equivalents
Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash 
Restricted cash
Restricted cash consists of approximately $6 million and $21 million at December 31, 2014 and 2013, respectively, and is included in other current assets on the Consolidated Balance Sheets. Restricted cash in 2013 primarily related to escrow accounts established as part of the settlement agreement with certain California utilities, which was settled in 2014.
Accounts receivable 
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories 
Inventories
All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. The following table presents a summary of inventories.
 
Years ended December 31,
 
2014
 
2013
 
(Millions)
Material, supplies and other
$
43

 
$
43

Crude oil production in transit
2

 
10

Natural gas in underground storage
—

 
13

 
$
45

 
$
66


During 2014, we assigned our remaining natural gas storage capacity agreement to a third party resulting in a loss of approximately $14 million and sold the remaining natural gas stored under this agreement for a loss of approximately $4 million reflected in gas management expenses in the Consolidated Statements of Operations. We recognized lower of cost or market writedowns on natural gas in storage of $1 million in both 2014 and 2013 and $11 million in 2012.
Properties and equipment 
Properties and equipment
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves related to our discontinued operations and are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.
Other capitalized costs 
Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations.
Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization 
Depreciation, depletion and amortization
Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
Impairment of long-lived assets 
Impairment of long-lived assets
We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.
Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities 
Contingent liabilities
Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations 
Asset retirement obligations
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities 
Cash flows from revolving credit facilities
Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities 
Derivative instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
 
Derivative Treatment
  
Accounting Method
 
Normal purchases and normal sales exception
  
Accrual accounting
 
Designated in a qualifying hedging relationship
  
Hedge accounting
 
All other derivatives
  
Mark-to-market accounting
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be, or is no longer expected to be, highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
•
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;
•
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to gas management and for which we have not elected the normal purchases and normal sales exception;
•
the ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
•
realized gains and losses on all derivatives that settle financially;
•
realized gains and losses on derivatives held for trading purposes; and
•
realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product revenues 
Product revenues
Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2014 and 2013 was insignificant. Additionally, natural gas revenues include $5 million and $423 million in 2013 and 2012, respectively, of realized gains from derivatives designated as cash flow hedges of our production sold.
Gas management revenues and expenses 
Gas management revenues and expenses
Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas, oil and NGLs purchased from working interest owners in operated wells and other area third-party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
Charges for unutilized transportation capacity included in gas management expenses were $57 million, $61 million and $46 million in 2014, 2013 and 2012, respectively.
Capitalization of interest 
Capitalization of interest
We capitalize interest during construction on projects with construction periods of at least three months and a total estimated project cost in excess of $1 million. We use the weighted average rate of our outstanding debt (see Note 7).
Income taxes 
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years.
Employee stock-based compensation 
Employee stock-based compensation
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Foreign exchange 
Foreign exchange
Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
Earnings (loss) per common share 
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 3).
Recently Issued Accounting Standards (Policies)
New Accounting Pronouncements, Policy [Policy Text Block]
Recently Issued Accounting Standards
In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of discontinued operations. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption is permitted but only for disposals (or classifications that are held for sale) that have not been reported in financial statements previously issued or available for use. We elected to early adopt this standard during the third quarter of 2014. As such, any disposals which meet the criteria above are reported as discontinued operations (see Note 2).
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows.
In August 2014, the FASB issued ASU No. 2014‑15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. The Company expects to adopt ASU 2014‑15 in fiscal year 2016 and the Company does not expect the adoption of ASU 2014‑15 to have a significant impact on its Consolidated Financial Statements or related disclosures.
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Tables)
Schedule of Inventory, Current [Table Text Block]
The following table presents a summary of inventories.
 
Years ended December 31,
 
2014
 
2013
 
(Millions)
Material, supplies and other
$
43

 
$
43

Crude oil production in transit
2

 
10

Natural gas in underground storage
—

 
13

 
$
45

 
$
66

Discontinued Operations (Tables)
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block] 
Summarized Results of Discontinued Operations
For the year ended December 31, 2014
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
189

 
$
163

 
$
352

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
41

 
$
37

 
$
78

Gathering, processing and transportation
70

 
1

 
71

Taxes other than income
16

 
28

 
44

Exploration
—

 
4

 
4

Depreciation, depletion and amortization
11

 
42

 
53

Impairment of assets held for sale
45

 
—

 
45

General and administrative
4

 
16

 
20

Other—net
—

 
12

 
12

Total costs and expenses
187

 
140

 
327

Operating income (loss)
2

 
23

 
25

Interest capitalized
1

 
—

 
1

Investment income and other
6

 
19

 
25

Income (loss) from discontinued operations before income taxes
9

 
42

 
51

Provision (benefit) for income taxes(a)
2

 
7

 
9

Income (loss) from discontinued operations
$
7

 
$
35

 
$
42


__________
(a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock.
For the year ended December 31, 2013
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
178

 
$
152

 
$
330

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
44

 
$
37

 
$
81

Gathering, processing and transportation
80

 
3

 
83

Taxes other than income
15

 
24

 
39

Exploration
1

 
7

 
8

Depreciation, depletion and amortization
48

 
34

 
82

Impairment of producing properties and costs of acquired unproved reserves
192

 
3

 
195

Gain on sale of Powder River Basin deep rights leasehold
(36
)
 
—

 
(36
)
General and administrative
6

 
14

 
20

Other—net
5

 
—

 
5

Total costs and expenses
355

 
122

 
477

Operating income (loss)
(177
)
 
30

 
(147
)
Interest capitalized
4

 
—

 
4

Investment income and other
4

 
21

 
25

Income (loss) from discontinued operations before income taxes
(169
)
 
51

 
(118
)
Provision (benefit) for income taxes(a)
(62
)
 
31

 
(31
)
Income (loss) from discontinued operations
$
(107
)
 
$
20

 
$
(87
)
__________
(a) International income tax provision for 2013 includes $10 million of deferred tax expense for the Argentina capital gains tax that was enacted in 2013.

For the year ended December 31, 2012
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
180

 
$
137

 
$
317

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
65

 
$
32

 
$
97

Gathering, processing and transportation
74

 
2

 
76

Taxes other than income
19

 
24

 
43

Gas management, including charges for unutilized pipeline capacity
1

 
—

 
1

Exploration
1

 
11

 
12

Depreciation, depletion and amortization
62

 
27

 
89

Impairment of producing properties and costs of acquired unproved reserves
102

 
—

 
102

Gain on sale of Barnett Shale and Arkoma Basin holdings
(38
)
 
—

 
(38
)
General and administrative
10

 
14

 
24

Other—net
(1
)
 
—

 
(1
)
Total costs and expenses
295

 
110

 
405

Operating income (loss)
(115
)
 
27

 
(88
)
Interest capitalized
6

 
—

 
6

Investment income and other
4

 
27

 
31

Income (loss) from discontinued operations before income taxes
(105
)
 
54

 
(51
)
Provision (benefit) for income taxes
(38
)
 
24

 
(14
)
Income (loss) from discontinued operations
$
(67
)
 
$
30

 
$
(37
)
Summarized Results of Discontinued Operations 
.
Balance Sheet Disclosures by Disposal Groups, Including Discontinued Operations [Table Text Block] 
Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations
December 31, 2014
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Assets classified as held for sale
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
—

 
$
29

 
$
29

Accounts receivable
—

 
25

 
25

Inventories
1

 
7

 
8

Other
—

 
14

 
14

Total current assets
1

 
75

 
76

Investments
18

 
134

 
152

Properties and equipment (successful efforts method of accounting)(a)
132

 
445

 
577

Less—accumulated depreciation, depletion and amortization
(10
)
 
(228
)
 
(238
)
Properties and equipment, net
122

 
217

 
339

Other noncurrent assets
—

 
6

 
6

Total assets classified as held for sale—discontinued operations
$
141

 
$
432

 
$
573

Total assets classified as held for sale—continuing operations (Note 4)
200

 
—

 
200

Total assets classified as held for sale on the Consolidated Balance Sheets
$
341

 
$
432

 
$
773

 
 
 
 
 
 
Liabilities associated with assets held for sale
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
—

 
$
34

 
$
34

Accrued and other current liabilities
3

 
23

 
26

Total current liabilities
3

 
57

 
60

Deferred income taxes
—

 
13

 
13

Long-term debt
—

 
2

 
2

Asset retirement obligations
45

 
7

 
52

Other noncurrent liabilities
—

 
3

 
3

Total liabilities associated with assets held for sale—discontinued operations
$
48

 
$
82

 
$
130

Total liabilities associated with assets held for sale—continuing operations (Note 4)
$
2

 
$
—

 
$
2

Total liabilities associated with assets held for sale on the Consolidated Balance Sheets
$
50

 
$
82

 
$
132

__________
(a) Domestic includes a $45 million impairment of the net assets of the Powder River Basin.

December 31, 2013
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Assets classified as held for sale
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
—

 
$
51

 
$
51

Accounts receivable
—

 
18

 
18

Inventories
1

 
5

 
6

Other
—

 
17

 
17

Total current assets
1

 
91

 
92

Investments
17

 
125

 
142

Properties and equipment (successful efforts method of accounting)
166

 
360

 
526

Less—accumulated depreciation, depletion and amortization
—

 
(194
)
 
(194
)
Properties and equipment, net
166

 
166

 
332

Total assets classified as held for sale—discontinued operations(a)
$
184

 
$
382

 
$
566

Total assets classified as held for sale—continuing operations (Note 4)(a)
148

 
—

 
148

Total assets classified as held for sale on the Consolidated Balance Sheets(a)
$
332

 
$
382

 
$
714

 
 
 
 
 
 
Liabilities associated with assets held for sale
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
—

 
$
18

 
$
18

Accrued and other current liabilities
3

 
20

 
23

Total current liabilities
3

 
38

 
41

Deferred income taxes
—

 
12

 
12

Long-term debt
—

 
5

 
5

Asset retirement obligations
47

 
4

 
51

Total liabilities associated with assets held for sale—discontinued operations(a)
$
50

 
$
59

 
$
109

Total liabilities associated with assets held for sale—continuing operations (Note 4)
2

 
—

 
2

Total liabilities associated with assets held for sale on the Consolidated Balance Sheets(a)
$
52

 
$
59

 
$
111

__________
(a) Noncurrent assets and liabilities as of December 31, 2013 that are attributable to discontinued operations have been reflected in other noncurrent assets and liabilities on the Consolidated Balance Sheet as of December 31, 2013.
Earnings (Loss) Per Common Share from Continuing Operations (Tables)
Earnings (Loss) Per Common Share from Continuing Operations 
The following table summarizes the calculation of earnings per share.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
$
129

 
$
(1,092
)
 
$
(174
)
Basic weighted-average shares
202.7

 
200.5

 
198.8

Effect of dilutive securities(a):
 
 
 
 
 
Nonvested restricted stock units and awards
2.7

 
 
 
 
Stock options
0.9

 
 
 
 
Diluted weighted-average shares
206.3

 
200.5

 
198.8

Earnings (loss) per common share from continuing operations:
 
 
 
 
 
Basic
$
0.63

 
$
(5.45
)
 
$
(0.87
)
Diluted
$
0.62

 
$
(5.45
)
 
$
(0.87
)

 __________
(a) For 2013 and 2012, approximately 2.5 million and 1.9 million, respectively, weighted-average nonvested restricted stock units and awards and 1.1 million and 1.0 million, respectively, weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.
Stock Options Outstanding Excluded from Computation of Weighted-Average Stock Options 
The table below includes information related to stock options that were outstanding at December 31, 2014, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
 
 
 
 
 
 
 
2014
 
2013
 
2012
Options excluded (millions)
1.4

 
0.4

 
1.3

Weighted-average exercise price of options excluded
$
18.42

 
$
20.24

 
$
18.17

Exercise price range of options excluded
$16.46 - $21.81

 
$20.21  - $20.97

 
$16.46  - $20.97

Fourth quarter weighted-average market price
$
15.96

 
$
19.97

 
$
16.15

Asset Sales, Impairments and Exploration Expenses (Tables)
Summary of Significant Gains or Losses Reflected in Impairment of Producing Properties and Costs of Acquired Unproved Reserves, Goodwill Impairment and Other-Net within Costs and Expenses 
The following table presents a summary of significant impairments of producing properties and costs of acquired unproved reserves and impairment of equity method investments.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Impairment of producing properties and costs of acquired unproved reserves(a)
$
20

 
$
860

 
$
123

Impairment of equity method investment in Appalachian Basin
$
—

 
$
20

 
$
—


 __________
(a)
Excludes related impairments of unproved leasehold included in exploration expenses.
Summary of Exploration Expenses 
The following table presents a summary of exploration expenses.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Geologic and geophysical costs
$
11

 
$
18

 
$
12

Impairments of exploratory area well costs and dry hole costs
88

 
3

 
1

Unproved leasehold property impairments, amortization and expiration
74

 
402

 
58

Total exploration expenses
$
173

 
$
423

 
$
71

Properties and Equipment (Tables)
Properties and Equipment, at Cost 
Properties and equipment is carried at cost and consists of the following:
 
 
Estimated
Useful
Life(a)
(Years)
 
December 31,
 
2014
 
2013
 
 
 
(Millions)
Proved properties
(b)
 
$
10,386

 
$
10,955

Unproved properties
(c)
 
394

 
316

Gathering, processing and other facilities
15-25
 
251

 
209

Construction in progress
(c)
 
541

 
353

Other
3-40
 
181

 
178

Total properties and equipment, at cost
 
 
11,753

 
12,011

Accumulated depreciation, depletion and amortization
 
 
(4,911
)
 
(5,251
)
Properties and equipment—net
 
 
$
6,842

 
$
6,760

__________
(a)
Estimated useful lives are presented as of December 31, 2014.
(b)
Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
(c)
Unproved properties and construction in progress are not yet subject to depreciation and depletion.
Rollforward of Asset Retirement Obligation 
A rollforward of our asset retirement obligations for the years ended 2014 and 2013 is presented below.
 
 
2014
 
2013
 
(Millions)
Balance, January 1
$
308

 
$
261

Liabilities incurred
19

 
11

Liabilities settled
(2
)
 
(1
)
Liabilities associated with assets sold
(65
)
 
—

Estimate revisions
(78
)
 
17

Accretion expense(a)
19

 
20

Balance, December 31
$
201

 
$
308

Amount reflected as current
$
3

 
$
3

__________
(a)
Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
Accounts Payable and Accrued and Other Current Liabilities (Tables)
Accounts Payable 
Accounts Payable
 
December 31,
 
2014
 
2013
 
(Millions)
Trade
$
215

 
$
208

Accrual for capital expenditures
313

 
225

Royalties
125

 
130

Cash overdrafts
—

 
35

Other
59

 
36

 
$
712

 
$
634

Accrued and Other Current Liabilities 
Accrued and other current liabilities
 
December 31,
 
2014
 
2013
 
(Millions)
Taxes other than income taxes
$
41

 
$
41

Accrued interest
53

 
43

Compensation and benefit related accruals
55

 
52

Other, including other loss contingencies
28

 
31

 
$
177

 
$
167

Debt and Banking Arrangements (Tables)
Debt
As of the indicated dates, our debt consisted of the following:
 
 
December 31,
 
2014 (a)
 
2013 (a)
 
(Millions)
5.250% Senior Notes due 2017
$
400

 
$
400

6.000% Senior Notes due 2022
1,100

 
1,100

5.250% Senior Notes due 2024
500

 
—

Credit facility agreement
280

 
410

Other
1

 
2

Total debt
$
2,281

 
$
1,912

Less: Current portion of long-term debt
1

 
1

Total long-term debt
$
2,280

 
$
1,911

__________
(a)
Interest paid on debt totaled $97 million and $91 million for 2014 and 2013, respectively.
Provision (Benefit) for Income Taxes (Tables)
Provision (Benefit) for Income Taxes from Continuing Operations 
The provision (benefit) for income taxes from continuing operations includes:
 
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Provision (benefit):
 
 
 
 
 
Current:
 
 
 
 
 
Federal
$
(3
)
 
$
(29
)
 
$
49

State
1

 
1

 
4

 
(2
)
 
(28
)
 
53

Deferred:
 
 
 
 
 
Federal
76

 
(549
)
 
(125
)
State
1

 
(47
)
 
(12
)
 
77

 
(596
)
 
(137
)
Total provision (benefit)
$
75

 
$
(624
)
 
$
(84
)
Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate 
Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Provision (benefit) at statutory rate
$
71

 
$
(604
)
 
$
(90
)
Increases (decreases) in taxes resulting from:
 
 
 
 
 
State income taxes (net of federal benefit)
3

 
(111
)
 
(6
)
State income tax change in valuation allowance (net of federal benefit)
(1
)
 
80

 
—

State income tax legislation change (net of federal benefit)
9

 
—

 
—

Effective state income tax rate change (net of federal benefit)
(9
)
 
(3
)
 
—

Alternative minimum tax credits
—

 
—

 
11

Other
2

 
14

 
1

Provision (benefit) for income taxes
$
75

 
$
(624
)
 
$
(84
)
Significant Components of Deferred Tax Liabilities and Deferred Tax Assets 
Significant components of deferred tax liabilities and deferred tax assets are as follows:
 
December 31,
 
2014
 
2013
 
(Millions)
Deferred tax liabilities:
 
 
 
Properties and equipment
$
738

 
$
961

Derivatives, net
170

 
—

Other, net
17

 
23

Total deferred tax liabilities
925

 
984

Deferred tax assets:
 
 
 
Accrued liabilities and other
124

 
176

Alternative minimum tax credits
60

 
76

Loss carryovers
51

 
83

Derivatives, net
—

 
21

Other, net
32

 
—

Total deferred tax assets
267

 
356

Less: valuation allowance
114

 
99

Total net deferred tax assets
153

 
257

Net deferred tax liabilities
$
772

 
$
727

Contingent Liabilities and Commitments (Tables)
Commitment Under Contracts 
Our commitments under these contracts as of December 31, 2014 are as follows:
 
 
(Millions)
2015
$
177

2016
162

2017
149

2018
138

2019
126

Thereafter
389

 
 

Total
$
1,141

Future Minimum Annual Rentals Under Noncancelable Operating Leases 
Future minimum annual rentals under noncancelable operating leases as of December 31, 2014, are payable as follows:
 
(Millions)
2015
$
37

2016
32

2017
11

2018
7

2019
7

Thereafter
15

 
 
Total
$
109

Stock-Based Compensation (Tables)
Summary of Stock Option Activity and Related Information 
The following summary reflects stock option activity and related information for the year ended December 31, 2014.
  
WPX Plan
Stock Options
Options
 
Weighted-
Average
Exercise
Price
 
Aggregate
Intrinsic
Value
 
(Millions)
 
 
 
(Millions)
Outstanding at December 31, 2013(a)
4.1

 
$
13.27

 
$
29

Granted
0.4

 
$
19.03

 
 
Exercised
(1.3
)
 
$
11.11

 
 
Forfeited
(0.1
)
 
$
15.39

 
 
Outstanding at December 31, 2014(a)
3.1

 
$
14.80

 
$
2

Exercisable at December 31, 2014
2.7

 
$
14.26

 
$
2

__________
(a)
Includes approximately 137 thousand shares held by Williams’ employees at a weighted average price of $10.64 per share at December 31, 2014 and 344 thousand shares held by Williams' employees at a weighted average price of $9.24 per share at December 31, 2013.
Additional Information about Stock Options Outstanding and Exercisable 
The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2014.
 
WPX Plan
 
Stock Options Outstanding
 
Stock Options Exercisable
Range of Exercise Prices
Options
 
Weighted-
Average
Exercise
Price
 
Weighted-
Average
Remaining
Contractual
Life
 
Options
 
Weighted-
Average
Exercise
Price
 
Weighted-
Average
Remaining
Contractual
Life
 
(Millions)
 
 
 
(Years)
 
(Millions)
 
 
 
(Years)
$ 6.02 to $10.68
0.5

 
$
7.59

 
2.8
 
0.5

 
$
7.59

 
2.8
$ 11.32 to $13.46
0.6

 
$
11.82

 
4.0
 
0.6

 
$
11.82

 
4.0
$14.41 to $18.23
1.5

 
$
16.39

 
6.1
 
1.2

 
$
16.36

 
5.6
$19.95 to $21.81
0.5

 
$
20.61

 
5.0
 
0.4

 
$
20.24

 
3.2
Total
3.1

 
$
14.80

 
5.0
 
2.7

 
$
14.26

 
4.4
Estimated Fair Value at Date of Grant of Options for Common Stock and Date of Conversion for Awards using Black Scholes Option Pricing Model 
The estimated fair value at date of grant of options for our common stock in each respective year, using the Black-Scholes option pricing model, is as follows:
 
WPX Plan
 
2014
 
2013
 
2012
Weighted-average grant date fair value of options granted
$
18.94

 
$
6.04

 
$
7.79

Weighted-average assumptions:
 
 
 
 
 
Dividend yield
—

 
—

 
—

Volatility
43.0
%
 
42.8
%
 
43.8
%
Risk-free interest rate
1.85
%
 
1.06
%
 
1.17
%
Expected life (years)
5.9

 
6.0

 
6.0

Summary of Nonvested Restricted Stock Unit Activity and Related Information 
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2014.
 
WPX Plan
Restricted Stock Units
Shares
 
Weighted-
Average
Fair Value(a)
 
(Millions)
 
 
Nonvested at December 31, 2013
5.2

 
$
16.97

Granted
2.5

 
$
18.37

Forfeited
(0.7
)
 
$
16.92

Vested
(1.9
)
 
$
16.92

Nonvested at December 31, 2014
5.1

 
$
17.58

__________
(a)
Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.
Other Restricted Stock Unit Information 
Other restricted stock unit information
 
WPX Plan
 
2014
 
2013
 
2012
Weighted-average grant date fair value of restricted stock units granted during the year, per share
$
18.37

 
$
14.97

 
$
17.35

Total fair value of restricted stock units vested during the year (millions)
$
33

 
$
18

 
$
14

Fair Value Measurements (Tables)
Assets and Liabilities Measured at Fair Value on Recurring Basis 
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, and margin deposits and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
December 31, 2014
 
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
(Millions)
 
 
 
(Millions)
Energy derivative assets
$
14

 
$
517

 
$
5

 
$
536

 
$
30

 
$
26

 
$
1

 
$
57

Energy derivative liabilities
$
32

 
$
10

 
$
—

 
$
42

 
$
83

 
$
38

 
$
1

 
$
122

Total debt(a)
$
—

 
$
2,218

 
$
—

 
$
2,218

 
$
—

 
$
1,938

 
$
—

 
$
1,938

__________
(a)
The carrying value of total debt, excluding capital leases, was $2,280 million and $1,910 million as of December 31, 2014 and 2013, respectively.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs 
The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
 
Years ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Beginning balance
$
—

 
$
(1
)
 
$
1

Realized and unrealized gains (losses):
 
 
 
 
 
Included in income (loss) from continuing operations
5

 
(2
)
 
3

Included in other comprehensive income (loss)
—

 
—

 
—

Purchases, issuances, and settlements
—

 
3

 
(5
)
Transfers out of Level 3
—

 
—

 
—

Ending balance
$
5

 
$
—

 
$
(1
)
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31
$
5

 
$
(1
)
 
$
(1
)
Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy 
The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
 
Total losses for
the years ended December 31,
 
 
 
2014 (a)
 
 
 
2013 (b)
 
 
 
2012 (c)
 
 
 
(Millions)
 
 
Impairments:
 
 
 
 
 
 
 
 
 
 
 
Producing properties and costs of acquired unproved reserves (Note 2 and Note 4)
$
20

 
 
 
$
1,055

 
 
 
$
225

 
 
Unproved leasehold
—

 
 
 
317

 
 
 
—

 
 
Equity method investment (Note 4)
—

 
 
 
20

 
 
 
—

 
 
 
$
20

 
 
 
$
1,392

 
  
 
$
225

 
  
__________
(a)
As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:
•
$11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.
•
$9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties.

(b)
As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:
•
$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
•
$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.
•
$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
•
$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
•
$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.

(c)
As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:
•
$102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
•
$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
Derivatives and Concentration of Credit Risk (Tables)
DerivativeGainLoss [Table Text Block] 
The following table presents the net gain (loss) related to our energy commodity derivatives.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
 
Gain (loss) from derivatives related to production not designated as hedging instruments (a)
$
515

 
$
(57
)
 
$
66

Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)
(81
)
 
(67
)
 
12

Net gain (loss) on derivatives not designated as hedges
$
434

 
$
(124
)
 
$
78

__________
(a)
Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.
(b)
Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.
The following table presents the net gain (loss) related to our energy commodity derivatives.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
 
Gain (loss) from derivatives related to production not designated as hedging instruments (a)
$
515

 
$
(57
)
 
$
66

Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)
(81
)
 
(67
)
 
12

Net gain (loss) on derivatives not designated as hedges
$
434

 
$
(124
)
 
$
78

__________
(a)
Includes payments totaling $4 million and $11 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $29 million for the year ended December 31, 2012.
(b)
Includes payments totaling $120 million and $6 million for the years ended December 31, 2014 and 2013, respectively, and receipts totaling $17 million for the year ended December 31, 2012.
Derivative Volumes that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production 
Derivatives related to production
The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of December 31, 2014.
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
2015
 
Fixed Price Swaps
 
Henry Hub
 
(442
)
 
$
4.10

Natural Gas
 
2015
 
Costless Collars
 
Henry Hub
 
(50
)
 
$ 4.00 - 4.50
Natural Gas
 
2015
 
Basis Swaps
 
NGPL
 
(13
)
 
$
(0.16
)
Natural Gas
 
2015
 
Basis Swaps
 
Rockies
 
(150
)
 
$
(0.11
)
Natural Gas
 
2015
 
Basis Swaps
 
San Juan
 
(85
)
 
$
(0.10
)
Natural Gas
 
2015
 
Basis Swaps
 
SoCal
 
(20
)
 
$
0.18

Natural Gas
 
2016
 
Fixed Price Swaps
 
Henry Hub
 
(200
)
 
$
3.98

Natural Gas
 
2016
 
Swaptions
 
Henry Hub
 
(90
)
 
$
4.23

Natural Gas
 
2017
 
Swaptions
 
Henry Hub
 
(65
)
 
$
4.19

Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
2015
 
Fixed Price Swaps
 
WTI
 
(20,236
)
 
$
94.88

Crude Oil
 
2015
 
Swaptions
 
WTI
 
(882
)
 
$
97.29

Crude Oil
 
2016
 
Swaptions
 
WTI
 
(5,250
)
 
$
97.55

 
__________
(a)
Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.
(b)
Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.
(c)
The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.

Derivatives primarily related to transportation
    
The following table sets forth the derivative notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, which are included in our commodity derivatives portfolio as of December 31, 2014. The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.
 
Commodity
 
Period
 
Contract Type (a)
 
Location (b)
 
Notional Volume (c)
 
Natural Gas
 
2015
 
Basis Swaps
 
Multiple
 
(3
)
 
Natural Gas
 
2015
 
Index
 
Multiple
 
(118
)
 
Natural Gas
 
2016
 
Index
 
Multiple
 
(70
)
 
Natural Gas
 
2017
 
Index
 
Multiple
 
(70
)
 
Natural Gas
 
2018+
 
Index
 
Multiple
 
(379
)
 
__________
(a)
We enter into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.
(b)
We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.
(c)
Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
Fair Value of Energy Commodity Derivatives 
The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.
 
December 31,
 
2014
 
2013
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production not designated as hedging instruments
$
517

 
$
10

 
$
26

 
$
39

Derivatives related to physical marketing agreements not designated as hedging instruments
19

 
32

 
31

 
83

Total derivatives not designated as hedging instruments
$
536

 
$
42

 
$
57

 
$
122

Pre-Tax Gains and Losses for Energy Commodity Derivatives Designated as Cash Flow Hedges, as Recognized in Accumulated Other Comprehensive Income or Revenues 
The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.
 
Years Ended
December 31,
 
Classification
 
2014
 
2013
 
2012
 
 
 
 
(Millions)
Net gain recognized in other comprehensive income (loss) (effective portion)
$
—

 
$
—

 
$
90

 
AOCI
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)
$
—

 
$
5

 
$
434

 
Revenues
__________
(a)
Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas sales and oil and condensate sales.
Gross And Net Derivative Asset and Liability 
The following table presents our gross and net derivative assets and liabilities.
 
Gross Amount Presented on Balance Sheet
 
Netting Adjustments (a)
 
Cash Collateral Posted(Received)
 
Net Amount
December 31, 2014
(Millions)
Derivative assets with right of offset or master netting agreements
$
536

 
$
(25
)
 
$
—

 
$
511

Derivative liabilities with right of offset or master netting agreements
$
(42
)
 
$
25

 
$
17

 
$
—

 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
57

 
$
(50
)
 
$
—

 
$
7

Derivative liabilities with right of offset or master netting agreements
$
(122
)
 
$
50

 
$
52

 
$
(20
)
__________
(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.
Concentration of Receivables, Net of Allowances, by Product or Service 
The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31:
 
2014
 
2013
 
(Millions)
Receivables by product or service:
 
 
 
Sale of natural gas, crude and related products and services
$
340

 
$
339

Joint interest owners
106

 
168

Other
13

 
11

Total
$
459

 
$
518

Gross and Net Credit Exposure from Derivative Contracts 
The gross and net credit exposure from our derivative contracts as of December 31, 2014, is summarized as follows:
Counterparty Type
Gross Total
 
Net Total
 
(Millions)
Gas and electric utilities, integrated oil and gas companies, and other
$
4

 
$
4

Financial institutions (Investment Grade) (a)
533

 
508

 
537

 
512

Credit reserves
(1
)
 
(1
)
Credit exposure from derivatives
$
536

 
$
511

__________
(a)
We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.
Quarterly Financial Data (Tables)
Summarized Quarterly Financial Data 
Summarized quarterly financial data are as follows:
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
(Millions, except per-share amounts)
2014
 
Revenues
$
894

 
$
727

 
$
747

 
$
1,125

Operating costs and expenses
$
783

 
$
659

 
$
570

 
$
656

 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
—

 
$
(144
)
 
$
46

 
$
227

Income (loss) from discontinued operations
19

 
11

 
20

 
(8
)
Net income (loss)
$
19

 
$
(133
)
 
$
66

 
$
219

Amounts attributable to WPX Energy, Inc.:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
—

 
$
(144
)
 
$
46

 
$
227

   Income (loss) from discontinued operations
18

 
9

 
16

 
(8
)
Net income (loss)
$
18

 
$
(135
)
 
$
62

 
$
219

Basic earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
—

 
$
(0.71
)
 
$
0.23

 
$
1.11

   Income (loss) from discontinued operations
0.09

 
0.05

 
0.07

 
(0.03
)
Net income (loss)
$
0.09

 
$
(0.66
)
 
$
0.30

 
$
1.08

Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
—

 
$
(0.71
)
 
$
0.23

 
$
1.10

   Income (loss) from discontinued operations
0.09

 
0.05

 
0.07

 
(0.04
)
Net income (loss)
$
0.09

 
$
(0.66
)
 
$
0.30

 
$
1.06

2013
 
 
 
 
 
 
 
Revenues
$
552

 
$
722

 
$
581

 
$
576

Operating costs and expenses
$
634

 
$
612

 
$
621

 
$
1,024

 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(115
)
 
$
6

 
$
(105
)
 
$
(890
)
Income (loss) from discontinued operations
2

 
16

 
(11
)
 
(94
)
Net income (loss)
$
(113
)
 
$
22

 
$
(116
)
 
$
(984
)
Amounts attributable to WPX Energy, Inc.:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(115
)
 
$
6

 
$
(105
)
 
$
(878
)
   Income (loss) from discontinued operations
(1
)
 
12

 
(9
)
 
(95
)
Net income (loss)
$
(116
)
 
$
18

 
$
(114
)
 
$
(973
)
Basic and diluted earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(0.57
)
 
$
0.03

 
$
(0.52
)
 
$
(4.37
)
   Income (loss) from discontinued operations
(0.01
)
 
0.06

 
(0.05
)
 
(0.48
)
Net income (loss)
$
(0.58
)
 
$
0.09

 
$
(0.57
)
 
$
(4.85
)
Quarterly Financial Data Adjustments [Table Text Block] 
Summarized quarterly financial data has been retrospectively adjusted to reflect the historical operating results for the Powder River Basin and our international segment as discontinued operations. (See Note 2 of Notes to Consolidated Financial Statements.) The increases (decreases) to amounts previously reported in our Form 10-Q were as follows:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter (a)
 
Fourth
Quarter
 
(Millions, except per-share amounts)
 
(Increase, (Decrease))
2014
 
Revenues
$
(93
)
 
$
(87
)
 
$
47

 
N/A

Operating costs and expenses
$
(62
)
 
$
62

 
$
31

 
N/A

 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(19
)
 
$
(11
)
 
$
(15
)
 
N/A

Income (loss) from discontinued operations
19

 
11

 
15

 
N/A

Net income (loss)
$
—

 
$
—

 
$
—

 
N/A

Amounts attributable to WPX Energy, Inc.:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(18
)
 
$
(9
)
 
$
(16
)
 
N/A

   Income (loss) from discontinued operations
18

 
9

 
16

 
N/A

Net income (loss)
$
—

 
$
—

 
$
—

 
N/A

Basic earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(0.09
)
 
$
(0.05
)
 
$
(0.05
)
 
N/A

   Income (loss) from discontinued operations
0.09

 
0.05

 
0.05

 
N/A

Net income (loss)
$
—

 
$
—

 
$
—

 
N/A

Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
(0.09
)
 
$
(0.05
)
 
$
(0.05
)
 
N/A

   Income (loss) from discontinued operations
0.09

 
0.05

 
0.05

 
N/A

Net income (loss)
$
—

 
$
—

 
$
—

 
N/A

2013
 
 
 
 
 
 
 
Revenues
$
(79
)
 
$
(93
)
 
$
35

 
$
(81
)
Operating costs and expenses
$
(76
)
 
$
(77
)
 
$
22

 
$
(74
)
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(2
)
 
$
(16
)
 
$
3

 
$
94

Income (loss) from discontinued operations
2

 
16

 
(3
)
 
(94
)
Net income (loss)
$
—

 
$
—

 
$
—

 
$
—

Amounts attributable to WPX Energy, Inc.:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
1

 
$
(12
)
 
$
9

 
$
95

   Income (loss) from discontinued operations
(1
)
 
12

 
(9
)
 
(95
)
Net income (loss)
$
—

 
$
—

 
$
—

 
$
—

Basic and diluted earnings (loss) per common share:
 
 
 
 
 
 
 
   Income (loss) from continuing operations
$
0.01

 
$
(0.06
)
 
$
0.01

 
$
0.48

   Income (loss) from discontinued operations
(0.01
)
 
0.06

 
(0.01
)
 
(0.48
)
Net income (loss)
$
—

 
$
—

 
$
—

 
$
—

__________
(a)
Third quarter only represents changes related to international being reported as discontinued operations because we reported Powder River Basin operations as discontinued in the third-quarter 2014.
Supplemental Oil and Gas Disclosures (Tables)
Capitalized Costs 
Capitalized Costs
 
As of December 31,
 
2014
 
2013
 
(Millions)
Proved Properties
$
10,717

 
$
11,132

Unproved properties
394

 
324

 
11,111

 
11,456

Accumulated depreciation, depletion and amortization and valuation provisions
(4,698
)
 
(5,070
)
Net capitalized costs
$
6,413

 
$
6,386

Cost Incurred 
Cost Incurred
 
 
For the years ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Acquisition
$
294

 
$
57

 
$
111

Exploration
92

 
104

 
23

Development
1,376

 
939

 
1,130

 
$
1,762

 
$
1,100

 
$
1,264

Results of Operations 
Results of Operations
 
For the years ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Revenues:
 
 
 
 
 
Natural gas sales
$
1,002

 
$
896

 
$
1,193

Oil and condensate sales
724

 
534

 
376

Natural gas liquid sales
205

 
228

 
297

Net gain (loss) on derivatives not designated as hedges
515

 
(57
)
 
66

Other revenues
8

 
6

 
7

Total revenues
2,454

 
1,607

 
1,939

Costs:
 
 
 
 
 
Lease and facility operating
244

 
227

 
202

Gathering, processing and transportation
328

 
350

 
434

Taxes other than income
126

 
102

 
68

Exploration
173

 
423

 
71

Depreciation, depletion and amortization
810

 
858

 
884

Impairment of certain proved properties
15

 
772

 
48

Impairment of costs of acquired unproved reserves
5

 
88

 
75

Loss on sale of working interests in the Piceance Basin
196

 
—

 
—

General and administrative
264

 
262

 
259

Other (income) expense
12

 
12

 
16

Total costs
2,173

 
3,094

 
2,057

Results of operations
281

 
(1,487
)
 
(118
)
Provision (benefit) for income taxes
103

 
(543
)
 
(43
)
Exploration and production net income (loss)
$
178

 
$
(944
)
 
$
(75
)

Proved Reserves 
 
Natural Gas (Bcf)
 
Oil (MMBbls)
 
NGLs (MMBbls)
 
All Products (Bcfe)
Proved reserves at December 31, 2011
3,982.9

 
47.1

 
134.0

 
5,070.1

Revisions
(404.8
)
 
5.6

 
(21.1
)
 
(498.6
)
Purchases
5.8

 
—

 
—

 
5.8

Divestitures
(217.0
)
 
(0.3
)
 
(1.0
)
 
(224.8
)
Extensions and discoveries
409.2

 
28.5

 
8.9

 
633.8

Production
(407.0
)
 
(4.4
)
 
(10.4
)
 
(495.8
)
Proved reserves at December 31, 2012
3,369.1

 
76.5

 
110.4

 
4,490.5

Revisions
308.3

 
3.5

 
(25.4
)
 
177.2

Divestitures
(0.2
)
 
—

 
—

 
(0.5
)
Extensions and discoveries
312.0

 
28.8

 
8.1

 
533.8

Production
(359.4
)
 
(5.9
)
 
(7.4
)
 
(439.4
)
Proved reserves at December 31, 2013
3,629.8

 
102.9

 
85.7

 
4,761.6

Revisions
(198.3
)
 
(7.7
)
 
(13.4
)
 
(324.8
)
Purchases
6.0

 
4.2

 
0.8

 
36.5

Divestitures
(314.6
)
 
(1.8
)
 
(8.5
)
 
(376.6
)
Extensions and discoveries
362.1

 
42.4

 
12.5

 
691.3

Production
(335.4
)
 
(9.2
)
 
(6.3
)
 
(428.4
)
Proved reserves at December 31, 2014
3,149.6

 
130.8

 
70.8

 
4,359.6

 
 
 
 
 
 
 
 
Proved developed reserves:
 
 
 
 
 
 
 
December 31, 2012
2,170.7

 
23.7

 
64.9

 
2,702.6

December 31, 2013
2,265.2

 
36.8

 
48.6

 
2,777.7

December 31, 2014
2,090.0

 
60.0

 
43.9

 
2,713.8

 
 
 
 
 
 
 
 
Proved undeveloped reserves:
 
 
 
 
 
 
 
December 31, 2012
1,198.4

 
52.8

 
45.5

 
1,787.9

December 31, 2013
1,364.6

 
66.1

 
37.1

 
1,983.9

December 31, 2014
1,059.6

 
70.8

 
26.9

 
1,645.8

__________
(a)
Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.
Standardized Measure of Discounted Future Net Cash Flows 
Standardized Measure of Discounted Future Net Cash Flows
 
As of December 31,
 
2014
 
2013
 
(Millions)
Future cash inflows
$
26,444

 
$
24,547

Less:
 
 
 
Future production costs
12,641

 
12,148

Future development costs
3,426

 
3,789

Future income tax provisions
2,519

 
2,147

Future net cash flows
7,858

 
6,463

Less 10 percent annual discount for estimated timing of cash flows
3,975

 
3,499

Standardized measure of discounted future net cash inflows
$
3,883

 
$
2,964

 
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows 
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows
 
For the years ended December 31,
 
2014
 
2013
 
2012
 
(Millions)
Beginning of year
$
2,964

 
$
1,949

 
$
3,591

Sales of oil and gas produced, net of operating costs
(1,324
)
 
(1,040
)
 
(778
)
Net change in prices and production costs
303

 
1,198

 
(3,601
)
Extensions, discoveries and improved recovery, less estimated future costs
1,761

 
1,282

 
1,154

Development costs incurred during year
592

 
414

 
333

Changes in estimated future development costs
143

 
(736
)
 
50

Purchase of reserves in place, less estimated future costs
147

 
—

 
4

Sale of reserves in place, less estimated future costs
(391
)
 
(3
)
 
(272
)
Revisions of previous quantity estimates
(536
)
 
239

 
(232
)
Accretion of discount
383

 
225

 
481

Net change in income taxes
(142
)
 
(540
)
 
1,194

Other
(17
)
 
(24
)
 
25

Net changes
919

 
1,015

 
(1,642
)
End of year
$
3,883

 
$
2,964

 
$
1,949



Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Accounting Policies [Line Items]
 
 
 
 
Buyout of Transportation Agreement
$ 9 
$ 14 
 
 
Natural Gas Storage Revenue
 
4 
 
 
Equity Method Investment, Ownership Percentage
 
69.00% 
 
 
Share Based Compensation Arrangement By Share Based Payment Award Minimum Exercisable Period For Stock Options
 
3 years 
 
 
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Minimum
 
20.00% 
 
 
Ownership Interest In Voting Rights Of Investee Required For Significant Influence Maximum
 
50.00% 
 
 
Hedge gains realized from natural gas revenues
 
 
5 
423 
Charges for unutilized transportation capacity included in gas management expenses
 
57 
61 
46 
Projects with construction periods, minimum
 
3 months 
 
 
Total estimated project cost
 
1 
 
 
Share Based Compensation Arrangement By Share Based Payment Award Award Term
 
10 years 
 
 
Natural Gas
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
Inventory writedowns
 
1 
1 
11 
Domestic Segment
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
Restricted cash related to escrow accounts to settle agreement
21 
6 
21 
 
International
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds
 
$ 294 
 
 
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Inventories (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Inventory [Line Items]
 
 
Material Supplies And Other
$ 43 
$ 43 
Crude Inventory In Transit
2 
10 
Energy Related Inventory, Natural Gas in Storage
0 
13 
Inventories
$ 45 
$ 66 
Discontinued Operations - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended 3 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
Domestic
Dec. 31, 2013
Domestic
Dec. 31, 2012
Domestic
Dec. 31, 2014
International
Dec. 31, 2013
International
Dec. 31, 2012
International
Dec. 31, 2014
Gathering and Treating [Member]
Discontinued Operations [Member]
Dec. 31, 2014
Capacity [Member]
Discontinued Operations [Member]
Mar. 31, 2015
Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) on Disposition of Assets
 
 
$ 38 
 
 
 
 
 
$ 0 
 
 
$ 40 
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds
 
 
 
155 
 
 
294 
 
 
 
 
 
Equity Method Investment, Ownership Percentage
69.00% 
 
 
 
 
 
 
 
 
 
 
 
Impairment of Oil and Gas Properties, Disposal Group
45 
195 
102 
45 
 
 
0 
3 
0 
 
 
 
Contractual Obligation
1,141 
 
 
 
 
 
 
 
 
128 
172 
 
Noncontrolling interests in consolidated subsidiaries
109 
101 
 
 
 
 
 
 
 
 
 
 
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities
 
 
 
65 
36 
18 
65 
56 
50 
 
 
 
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities
 
 
 
11 
3 
20 
85 
43 
56 
 
 
 
Proceeds from Divestiture of Businesses
 
 
$ 306 
 
 
 
 
 
 
 
 
 
Discontinued Operations - Summarized Results of Discontinued Operations (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Deferred Tax Asset, Parent's Basis in Discontinued Operation
$ 18 
 
 
 
 
 
 
 
$ 18 
 
 
DeferredForeignIncomeTaxExpenseBenefit-Argentina
 
 
 
 
 
 
 
 
 
10 
 
Total revenues
 
 
 
 
 
 
 
 
352 
330 
317 
Disposal Group, Including Discontinued Operation, Lease Operating Expense
 
 
 
 
 
 
 
 
78 
81 
97 
Gathering, processing and transportation
 
 
 
 
 
 
 
 
71 
83 
76 
Disposal Group, Including Discontinued Operation Taxes other than income
 
 
 
 
 
 
 
 
44 
39 
43 
GasManagementExpenseDisposalGroup
 
 
 
 
 
 
 
 
 
 
1 
Exploration
 
 
 
 
 
 
 
 
4 
8 
12 
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
53 
82 
89 
Impairment of Oil and Gas Properties, Disposal Group
 
 
 
 
 
 
 
 
45 
195 
102 
Gain on sale of Powder River Basin deep rights leasehold
 
 
 
 
 
 
 
 
 
(36)
 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
 
(38)
General and administrative
 
 
 
 
 
 
 
 
20 
20 
24 
Other—net
 
 
 
 
 
 
 
 
12 
5 
(1)
Total costs and expenses
 
 
 
 
 
 
 
 
327 
477 
405 
Operating income (loss)
 
 
 
 
 
 
 
 
25 
(147)
(88)
Disposal Group including Discontinued Operation Interest Costs Capitalized
 
 
 
 
 
 
 
 
1 
4 
6 
Disposal Group Including Discontinued Operation Investment Income
 
 
 
 
 
 
 
 
25 
25 
31 
Disposal Group Including Discontinued Operation Income before Tax
 
 
 
 
 
 
 
 
51 
(118)
(51)
Discontinued Operation, Tax Effect of Discontinued Operation
 
 
 
 
 
 
 
 
9 
(31)
(14)
Income (loss) from discontinued operations
(8)
20 
11 
19 
(94)
(11)
16 
2 
42 
(87)
(37)
Domestic
 
 
 
 
 
 
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Total revenues
 
 
 
 
 
 
 
 
189 
178 
180 
Disposal Group, Including Discontinued Operation, Lease Operating Expense
 
 
 
 
 
 
 
 
41 
44 
65 
Gathering, processing and transportation
 
 
 
 
 
 
 
 
70 
80 
74 
Disposal Group, Including Discontinued Operation Taxes other than income
 
 
 
 
 
 
 
 
16 
15 
19 
GasManagementExpenseDisposalGroup
 
 
 
 
 
 
 
 
 
 
1 
Exploration
 
 
 
 
 
 
 
 
0 
1 
1 
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
11 
48 
62 
Impairment of Oil and Gas Properties, Disposal Group
 
 
 
 
 
 
 
 
45 
192 
102 
Gain on sale of Powder River Basin deep rights leasehold
 
 
 
 
 
 
 
 
 
(36)
 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
 
(38)
General and administrative
 
 
 
 
 
 
 
 
4 
6 
10 
Other—net
 
 
 
 
 
 
 
 
0 
5 
(1)
Total costs and expenses
 
 
 
 
 
 
 
 
187 
355 
295 
Operating income (loss)
 
 
 
 
 
 
 
 
2 
(177)
(115)
Disposal Group including Discontinued Operation Interest Costs Capitalized
 
 
 
 
 
 
 
 
1 
4 
6 
Disposal Group Including Discontinued Operation Investment Income
 
 
 
 
 
 
 
 
6 
4 
4 
Disposal Group Including Discontinued Operation Income before Tax
 
 
 
 
 
 
 
 
9 
(169)
(105)
Discontinued Operation, Tax Effect of Discontinued Operation
 
 
 
 
 
 
 
 
2 
(62)
(38)
Income (loss) from discontinued operations
 
 
 
 
 
 
 
 
7 
(107)
(67)
International
 
 
 
 
 
 
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Total revenues
 
 
 
 
 
 
 
 
163 
152 
137 
Disposal Group, Including Discontinued Operation, Lease Operating Expense
 
 
 
 
 
 
 
 
37 
37 
32 
Gathering, processing and transportation
 
 
 
 
 
 
 
 
1 
3 
2 
Disposal Group, Including Discontinued Operation Taxes other than income
 
 
 
 
 
 
 
 
28 
24 
24 
GasManagementExpenseDisposalGroup
 
 
 
 
 
 
 
 
 
 
0 
Exploration
 
 
 
 
 
 
 
 
4 
7 
11 
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
42 
34 
27 
Impairment of Oil and Gas Properties, Disposal Group
 
 
 
 
 
 
 
 
0 
3 
0 
Gain on sale of Powder River Basin deep rights leasehold
 
 
 
 
 
 
 
 
 
0 
 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
 
0 
General and administrative
 
 
 
 
 
 
 
 
16 
14 
14 
Other—net
 
 
 
 
 
 
 
 
12 
0 
0 
Total costs and expenses
 
 
 
 
 
 
 
 
140 
122 
110 
Operating income (loss)
 
 
 
 
 
 
 
 
23 
30 
27 
Disposal Group including Discontinued Operation Interest Costs Capitalized
 
 
 
 
 
 
 
 
0 
0 
0 
Disposal Group Including Discontinued Operation Investment Income
 
 
 
 
 
 
 
 
19 
21 
27 
Disposal Group Including Discontinued Operation Income before Tax
 
 
 
 
 
 
 
 
42 
51 
54 
Discontinued Operation, Tax Effect of Discontinued Operation
 
 
 
 
 
 
 
 
7 1
31 2
24 
Income (loss) from discontinued operations
 
 
 
 
 
 
 
 
$ 35 
$ 20 
$ 30 
Discontinued Operations Discontinued Operations- Balance Sheet Disclosures by Disposal Groups (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents
$ 29 
$ 51 
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net
25 
18 
Disposal Group, Including Discontinued Operation, Inventory
8 
6 
Disposal Group, Including Discontinued Operation, Other Assets, Current
14 
17 
Disposal Group Assets, Current
76 
92 
Disposal Group, Including Discontinued Operation, Investment
152 
142 
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment
577 
526 
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization
(238)
(194)
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net (Deprecated 2014-01-31)
339 
332 
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent
6 
 
Disposal Group, Including Discontinued Operation, Assets
573 
566 1
Assets Held for Sale, Continuing Operations
200 
148 1
Assets of disposal group classified as held for sale
773 
714 1
Disposal Group, Including Discontinued Operation, Accounts Payable
34 
18 
Disposal Group, Including Discontinued Operation, Accrued Liabilities
26 
23 
Disposal Group Liabilities, Current
60 
41 
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities
13 
12 
long term debt noncurrent disposal group
2 
5 
Disposal Group Asset Retirement Obligation Noncurrent
52 
51 
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent
3 
 
Disposal Group, Including Discontinued Operation, Liabilities
130 
109 1
Liabilities of Disposal Group in Continuing Operations
2 
2 
Liabilities of disposal group associated with assets held for sale
132 
111 1
International
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
Liabilities of Disposal Group in Continuing Operations
 
0 
Continuing Operations [Member]
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
Assets Held for Sale, Continuing Operations
200 
148 1
Liabilities of Disposal Group in Continuing Operations
 
2 
International
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents
29 
51 
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net
25 
18 
Disposal Group, Including Discontinued Operation, Inventory
7 
5 
Disposal Group, Including Discontinued Operation, Other Assets, Current
14 
17 
Disposal Group Assets, Current
75 
91 
Disposal Group, Including Discontinued Operation, Investment
134 
125 
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment
445 
360 
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization
(228)
(194)
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net (Deprecated 2014-01-31)
217 
166 
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent
6 
 
Disposal Group, Including Discontinued Operation, Assets
432 
382 1
Assets Held for Sale, Continuing Operations
0 
0 1
Assets of disposal group classified as held for sale
432 
382 1
Disposal Group, Including Discontinued Operation, Accounts Payable
34 
18 
Disposal Group, Including Discontinued Operation, Accrued Liabilities
23 
20 
Disposal Group Liabilities, Current
57 
38 
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities
13 
12 
long term debt noncurrent disposal group
2 
5 
Disposal Group Asset Retirement Obligation Noncurrent
7 
4 
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent
3 
 
Disposal Group, Including Discontinued Operation, Liabilities
82 
59 1
Liabilities of Disposal Group in Continuing Operations
0 
 
Liabilities of disposal group associated with assets held for sale
82 
59 1
Domestic
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents
0 
0 
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net
0 
0 
Disposal Group, Including Discontinued Operation, Inventory
1 
1 
Disposal Group, Including Discontinued Operation, Other Assets, Current
0 
0 
Disposal Group Assets, Current
1 
1 
Disposal Group, Including Discontinued Operation, Investment
18 
17 
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment
132 2
166 
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization
(10)
0 
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net (Deprecated 2014-01-31)
122 
166 
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent
0 
 
Disposal Group, Including Discontinued Operation, Assets
141 
184 1
Assets of disposal group classified as held for sale
341 
332 1
Disposal Group, Including Discontinued Operation, Accounts Payable
0 
0 
Disposal Group, Including Discontinued Operation, Accrued Liabilities
3 
3 
Disposal Group Liabilities, Current
3 
3 
Disposal Group, Including Discontinued Operation, Deferred Tax Liabilities
0 
0 
long term debt noncurrent disposal group
0 
0 
Disposal Group Asset Retirement Obligation Noncurrent
45 
47 
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent
0 
 
Disposal Group, Including Discontinued Operation, Liabilities
48 
50 1
Liabilities of Disposal Group in Continuing Operations
2 
 
Liabilities of disposal group associated with assets held for sale
$ 50 
$ 52 1
Earnings (Loss) Per Common Share from Continuing Operations (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
$ 227 
$ 46 
$ (144)
$ 0 
$ (878)
$ (105)
$ 6 
$ (115)
$ 129 
$ (1,092)
$ (174)
Basic weighted-average shares
 
 
 
 
 
 
 
 
202.7 
200.5 
198.8 
Diluted weighted-average shares
 
 
 
 
 
 
 
 
206.3 
200.5 1
198.8 1
Earnings (loss) per common share from continuing operations:
 
 
 
 
 
 
 
 
 
 
 
Basic (in dollars per share)
$ 1.11 
$ 0.23 
$ (0.71)
$ 0.00 
 
 
 
 
$ 0.63 
$ (5.45)
$ (0.87)
Diluted (in dollars per share)
$ 1.10 
$ 0.23 
$ (0.71)
$ 0.00 
 
 
 
 
$ 0.62 
$ (5.45)
$ (0.87)
Nonvested Restricted Stock Units
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements
 
 
 
 
 
 
 
 
2.7 
2.5 
1.1 
Stock Options
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements
 
 
 
 
 
 
 
 
0.9 
1.9 
1.0 
Earnings (Loss) Per Common Share from Continuing Operations - Stock Options Outstanding Excluded from Computation of Weighted-Average Stock Option (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Disclosure Stock Options Outstanding Excluded From Computation Of Weighted Average Stock Option [Abstract]
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
1.4 
0.4 
1.3 
Weighted-average exercise price of options excluded
$ 18.42 
$ 20.24 
$ 18.17 
Exercise price range of options excluded, lower limit
$ 16.46 
$ 20.21 
$ 16.46 
Exercise price range of options excluded, upper limit
$ 21.81 
$ 20.97 
$ 20.97 
Fourth quarter weighted-average market price
$ 15.96 
$ 19.97 
$ 16.15 
Asset Sales, Impairments and Exploration Expenses - Significant Adjustments with Domestic Operations (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended 3 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Dec. 31, 2014
Well
acre
MMcf
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
Other Property
Dec. 31, 2014
Legacy [Member]
Piceance Basin [Member]
Dec. 31, 2014
Pennsylvania [Member]
Dec. 31, 2014
Post Closing [Member]
Dec. 31, 2014
Marcellus Shale
Mar. 31, 2015
Subsequent Event
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Impairment Charge
 
 
 
 
 
$ 9 
 
 
 
 
 
Proceeds from sales of assets
 
 
374 
49 
310 
 
325 
300 
329 
 
 
Percentage Ownership Of Incentive Distribution Rights
 
 
10.00% 
 
 
 
 
 
 
 
 
Proved Developed and Undeveloped Reserves, Net
 
 
300,000.0 
 
 
 
 
 
 
 
 
Percentage of proved reserves attributed to sale of producing assets
 
 
6.00% 
 
 
 
 
 
 
 
 
Production Related To The Sale Of Working Interests
 
 
70 
 
 
 
 
 
 
 
 
Impairment of producing properties and costs of acquired unproved reserves
 
 
20 1
860 1
123 1
 
 
 
 
 
 
Impairment Equity method investment
 
 
0 
20 2
0 
 
 
 
 
 
 
Gain on sale of Powder River Basin deep rights leasehold
 
 
 
36 
 
 
 
 
 
 
 
Loss On Sale Of Working Interests
1 
195 
196 
0 
0 
 
 
 
 
 
 
Property, Plant and Equipment, Net
 
 
6,842 
6,760 
 
 
 
 
 
200 
 
Asset Retirement Obligation
 
 
201 
308 
261 
 
 
 
 
2 
 
Oil and Gas Property, Deep Rights, Acres Sold During Period
 
 
46,700 
 
 
 
 
 
 
 
 
Production related to sale
 
 
50 
 
 
 
 
 
 
 
 
Proved developed wells related to sale
 
 
63 
 
 
 
 
 
 
 
 
Oil and Gas Delivery Commitments and Contracts, Daily Production
 
 
260 
 
 
 
 
 
 
 
 
Cost Of Oil And Gas Services
 
 
24 
 
 
 
 
 
 
 
 
Gain (Loss) on Disposition of Proved Property
 
 
 
 
 
 
 
 
 
 
$ 75 
[2] As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.
Asset Sales, Impairments and Exploration Expenses (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 3 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
Piceance Basin [Member]
Dec. 31, 2013
Appalachian Basin
Dec. 31, 2013
Powder River Basin
Dec. 31, 2012
Powder River Basin
Dec. 31, 2013
Piceance
Dec. 31, 2012
Piceance
Dec. 31, 2014
Kokopelli area of Piceance Basin
Sep. 30, 2014
Kokopelli area of Piceance Basin
Dec. 31, 2013
Kokopelli area of Piceance Basin
Dec. 31, 2014
Green River Basin
Dec. 31, 2012
Green River Basin
Dec. 31, 2014
Other Property
Dec. 31, 2013
Impairment of Equity Method Investment in Appalachian Basin [Member]
Impairment Costs [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset impairment charges
$ 87 
$ 1,200 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Impairment of producing properties and costs of acquired unproved reserves
20 1
860 1
123 1
 
 
 
 
 
 
 
 
 
 
 
 
 
Impairment of producing properties and costs of acquired unproved reserves
 
 
 
 
 
85 
 
88 
75 
69 
19 
19 
 
 
 
 
Impairment Charge
 
 
 
 
772 
107 
102 
 
 
 
 
 
11 
 
 
 
Impairment of proved oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
48 
 
 
Gain on sale of Powder River Basin deep rights leasehold
 
36 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dry hole costs
88 
3 
1 
67 
 
 
 
 
 
 
 
 
 
 
16 
 
Unproved leasehold property impairment, amortization and expiration
74 
402 
58 
 
317 
 
 
 
 
 
 
 
 
 
41 
 
Investment income, impairment of equity method investment and other
$ 1 
$ (19)
$ 1 
 
 
 
 
 
 
 
 
 
 
 
 
$ 20 
Asset Sales, Impairments and Exploration Expenses - Summary of Exploration Expenses (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Extractive Industries [Abstract]
 
 
 
Geologic and geophysical costs
$ 11 
$ 18 
$ 12 
Dry hole costs
88 
3 
1 
Unproved leasehold property impairment, amortization and expiration
74 
402 
58 
Capitalized Exploratory Well Costs
37 
 
 
Total exploration expense
173 
423 
71 
Other Property
 
 
 
Extractive Industries [Abstract]
 
 
 
Dry hole costs
16 
 
 
Unproved leasehold property impairment, amortization and expiration
$ 41 
 
 
Properties and Equipment - Carried at Cost (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2014
Proved properties
Dec. 31, 2013
Proved properties
Dec. 31, 2014
Unproved Properties
Dec. 31, 2013
Unproved Properties
Dec. 31, 2014
Gathering, Processing and Other Facilities
Dec. 31, 2013
Gathering, Processing and Other Facilities
Dec. 31, 2014
Gathering, Processing and Other Facilities
Minimum
Dec. 31, 2014
Gathering, Processing and Other Facilities
Maximum
Dec. 31, 2014
Construction in Progress
Dec. 31, 2013
Construction in Progress
Dec. 31, 2014
Other
Dec. 31, 2013
Other
Dec. 31, 2014
Other
Minimum
Dec. 31, 2014
Other
Maximum
Property, Plant and Equipment [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property and equipment, estimated useful life (years)
 
 
 
 
 
 
 
 
15 years 1
25 years 1
 
 
 
 
3 years 1
40 years 1
Properties and equipment-net, at cost
$ 11,753 
$ 12,011 
$ 10,386 1 2
$ 10,955 1 2
$ 394 1 3
$ 316 1 3
$ 251 1
$ 209 1
 
 
$ 541 1 3
$ 353 1 3
$ 181 1
$ 178 1
 
 
Accumulated depreciation, depletion and amortization
(4,911)
(5,251)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Properties and equipment-net
$ 6,842 
$ 6,760 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Properties and Equipment - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Well
Dec. 31, 2013
Dec. 31, 2012
Property, Plant and Equipment [Line Items]
 
 
 
Payments to Acquire Oil and Gas Property
$ 150 
 
 
Proceeds from sales of assets
374 
49 
310 
Percentage of working interest sold
49.00% 
 
 
Proved developed wells related to sale
63 
 
 
Funding commitment associated with joint development agreement
170 
 
 
Future wells associated with joint development agreement
400 
 
 
Piceance Basin [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Proved developed wells related to sale
100 
 
 
Proved Developed Reserves [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Payments to Acquire Oil and Gas Property
50 
 
 
Piceance Basin [Member] |
TRDC LLC (G2X) [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Proceeds from sales of assets
$ 50 
 
 
Properties and Equipment - Rollforward Asset Retirement Obligation (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Beginning Balance
$ 308 
$ 261 
Liabilities incurred during the period
19 
11 
Liabilities settled during the period
(2)
(1)
Asset Retirement Obligation, Liabilities associated with assets sold
65 
0 
Estimate revisions
(78)
17 
Accretion expense
19 1
20 1
Ending Balance
201 
308 
Amount reflected as current
$ 3 
$ 3 
Accounts Payable and Accrued and Other Current Liabilities - Accounts Payable (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Payables and Accruals [Abstract]
 
 
Trade
$ 215 
$ 208 
Accrual for capital expenditures
313 
225 
Royalties
125 
130 
Cash overdrafts
0 
35 
Other
59 
36 
Accounts payable
$ 712 
$ 634 
Accounts Payable and Accrued and Other Current Liabilities - Accrued and Other Current Liabilities (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Payables and Accruals [Abstract]
 
 
Taxes other than income taxes
$ 41 
$ 41 
Accrued interest
53 
43 
Compensation and benefit related accruals
55 
52 
Other, including other loss contingencies
28 
31 
Accrued And Other Current Liabilities
$ 177 
$ 167 
Debt and Banking Arrangements - Debt (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Debt Instrument [Line Items]
 
 
Total debt
$ 2,281 1
$ 1,912 1
Less: Current portion of long-term debt
1 1
1 1
Total long-term debt
2,280 1
1,911 1
5.250% Senior Notes due 2017
 
 
Debt Instrument [Line Items]
 
 
Total debt
400 1
400 1
6.000% Senior Notes due 2022
 
 
Debt Instrument [Line Items]
 
 
Total debt
1,100 1
1,100 1
5.250 % Senior Notes due 2024
 
 
Debt Instrument [Line Items]
 
 
Total debt
500 1
0 
Credit Facility Agreement
 
 
Debt Instrument [Line Items]
 
 
Total debt
280 1
410 1
Other
 
 
Debt Instrument [Line Items]
 
 
Total debt
$ 1 1
$ 2 1
Debt and Banking Arrangements - Debt - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Debt Instrument [Line Items]
 
 
Long-term debt, interest expense
$ 97 
$ 91 
5.250% Senior Notes due 2017
 
 
Debt Instrument [Line Items]
 
 
Debt instrument stated interest rate
5.25% 
5.25% 
Debt Instrument Maturity Year
2017 
2017 
6.000% Senior Notes due 2022
 
 
Debt Instrument [Line Items]
 
 
Debt instrument stated interest rate
6.00% 
6.00% 
Debt Instrument Maturity Year
2022 
2022 
5.250 % Senior Notes due 2024
 
 
Debt Instrument [Line Items]
 
 
Debt instrument stated interest rate
5.25% 
5.25% 
Debt Instrument Maturity Year
2024 
2024 
Debt and Banking Arrangements - Additional Information (Detail) (USD $)
12 Months Ended 12 Months Ended
Dec. 31, 2014
Contract
Dec. 31, 2014
Unsecured Revolving Credit Facility
Dec. 31, 2014
Unsecured Revolving Credit Facility
Federal Funds Rate
Dec. 31, 2014
Unsecured Revolving Credit Facility
one-month LIBOR
Nov. 30, 2011
5.250% Senior Notes due 2017
Sep. 30, 2014
Senior Notes
Nov. 30, 2011
6.000% Senior Notes due 2022
Sep. 30, 2014
5.250 % Senior Notes due 2024
Dec. 31, 2014
Change of Control
Dec. 31, 2014
Prior to December 31, 2015 [Member]
Dec. 31, 2014
After December 31, 2015 [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Debt, Long-term and Short-term, Combined Amount
 
 
 
 
$ 400,000,000 
 
$ 1,100,000,000.0 
$ 500,000,000 
 
 
 
Net proceeds from debt offering
 
 
 
 
 
494,000,000 
 
 
 
 
 
Debt redemption price as percentage of principal amount
100.00% 
 
 
 
 
 
 
 
 
 
 
Percentage of repurchase of notes on principal amount of notes
 
 
 
 
 
 
 
 
101.00% 
 
 
Credit facility agreement
 
1,500,000,000.0 
 
 
 
 
 
 
 
 
 
Debt instrument maturity period
 
5 years 
 
 
 
 
 
 
 
 
 
Debt instrument additional borrowing capacity
 
300,000,000 
 
 
 
 
 
 
 
 
 
Weighted average interest rate
 
3.01% 
 
 
 
 
 
 
 
 
 
Outstanding amount
 
280,000,000 
 
 
 
 
 
 
 
 
 
Basis spread on variable rate
 
 
0.50% 
1.00% 
 
 
 
 
 
 
 
Debt Instrument, Description of Variable Rate Basis
0.01875 
 
 
 
 
 
 
 
 
 
 
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate
0.88% 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Commitment Fee Percentage
0.30% 
 
 
 
 
 
 
 
 
 
 
Limit On Consolidated Indebtedness to Consolidated EBITDAX
3.75 
 
 
 
 
 
 
 
 
 
 
Reduction Attributable to Cash Maximum
50,000,000 
 
 
 
 
 
 
 
 
 
 
Minimum required ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness
 
 
 
 
 
 
 
 
 
1.25 
1.50 
Maximum ratio of debt to capitalization
60.00% 
 
 
 
 
 
 
 
 
 
 
Number of letter of credit agreements
3 
 
 
 
 
 
 
 
 
 
 
Letters of credit issued
$ 320,000,000 
 
 
 
 
 
 
 
 
 
 
Provision (Benefit) for Income Taxes - Provision (Benefit) for Income Taxes from Continuing Operations (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Current:
 
 
 
Federal
$ (3)
$ (29)
$ 49 
State
1 
1 
4 
Total current
(2)
(28)
53 
Deferred:
 
 
 
Federal
76 
(549)
(125)
State
1 
(47)
(12)
Total Deferred
77 
(596)
(137)
Total provision (benefit)
$ 75 
$ (624)
$ (84)
Provision (Benefit) for Income Taxes - Reconciliations from Provision (Benefit) for Income Taxes from Continuing Operations at Federal Statutory Rate (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Income Tax Disclosure [Abstract]
 
 
 
Provision (benefit) at statutory rate
$ 71 
$ (604)
$ (90)
Increases (decreases) in taxes resulting from:
 
 
 
State income taxes (net of federal benefit)
3 
(111)
(6)
State income tax change in valuation allowance (net of federal benefit)
(1)
80 
0 
Effective Income Tax Rate Reconciliation, Tax Contingency, State and Local, Amount
9 
 
 
Effective state income tax rate change (net of federal benefit)
(9)
(3)
0 
Alternative minimum tax credits
0 
0 
11 
Other
2 
14 
1 
Total provision (benefit)
$ 75 
$ (624)
$ (84)
Provision (Benefit) for Income Taxes - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Mar. 31, 2014
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Provision For Income Taxes [Line Items]
 
 
 
 
 
State net operating loss carryovers expire percent
 
 
90.00% 
 
 
State net operating loss carryovers expiration year
 
 
2029 
 
 
Deferred Other Tax Expense (Benefit)
$ 9 
$ 9 
 
 
 
Excess Tax Benefit from Share-based Compensation, Financing Activities
 
 
7 
 
 
Alternative minimum tax credits
 
 
0 
0 
11 
Federal
 
 
 
 
 
Provision For Income Taxes [Line Items]
 
 
 
 
 
Operating Loss Carryforwards
114 
 
114 
 
 
State
 
 
 
 
 
Provision For Income Taxes [Line Items]
 
 
 
 
 
Operating Loss Carryforwards
875 
 
875 
825 
 
Domestic
 
 
 
 
 
Provision For Income Taxes [Line Items]
 
 
 
 
 
Income tax cash paid (refund)
 
 
$ 9 
$ (26)
$ 40 
Provision (Benefit) for Income Taxes - Significant Components of Deferred Tax Liabilities and Deferred Tax Assets (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Deferred tax liabilities:
 
 
Properties and equipment
$ 738 
$ 961 
Deferred Tax Liabilities, Derivatives
170 
0 
Other, net
17 
23 
Total deferred tax liabilities
925 
984 
Deferred tax assets:
 
 
Accrued liabilities and other
124 
176 
Alternative minimum tax credits
60 
76 
Loss carryovers
51 
83 
Deferred Tax Assets, Derivative Instruments
0 
21 
Other, net
32 
0 
Total deferred tax assets
267 
356 
Less: valuation allowance
114 
99 
Total net deferred tax assets
153 
257 
Net deferred tax liabilities
$ 772 
$ 727 
Contingent Liabilities and Commitments - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended 1 Months Ended 97 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2014
Purchase agreement
Marcellus Shale
Sep. 30, 2006
Royalty Litigation
Claim
Jul. 31, 2008
Royalty Litigation
Dec. 31, 2014
Royalty Litigation
Dec. 31, 2013
Royalty Litigation
Dec. 31, 2014
Assets Held-for-sale [Member]
Dec. 31, 2014
Discontinued Operations [Member]
Capacity [Member]
Dec. 31, 2014
Discontinued Operations [Member]
Assets Held-for-sale [Member]
Loss Contingencies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Number of claims reserved for court resolution
 
 
 
 
2 
 
 
 
 
 
 
Loss Contingency, Damages Sought, Value
 
 
 
 
 
$ 20 
 
 
 
 
 
Processing, treating and transportation costs used in the calculation of federal royalties
113 
 
 
 
 
 
 
 
 
 
 
Loss contingencies associated with royalty litigation
 
 
 
 
 
 
16 
16 
 
 
 
Commitments to provide service to an equity investee and others
305 
 
 
 
 
 
 
 
 
 
 
Service commitment period
6 years 
 
 
 
 
 
 
 
 
 
 
Contractual Obligation
1,141 
 
 
 
 
 
 
 
88 
172 
43 
Volume of natural gas production per day
260 
 
 
200,000 
 
 
 
 
 
 
 
Contract term
 
 
 
12 years 
 
 
 
 
 
 
 
Total rent expenses
$ 27 
$ 27 
$ 19 
 
 
 
 
 
 
 
 
Contingent Liabilities and Commitments - Commitments Under Contracts (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
 
2015
$ 177 
2016
162 
2017
149 
2018
138 
2019
126 
Thereafter
389 
Total
$ 1,141 
Contingent Liabilities and Commitments - Future Minimum Annual Rentals Under Noncancelable Operating Leases (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
 
2015
$ 37 
2016
32 
2017
11 
2018
7 
2019
7 
Thereafter
15 
Total
$ 109 
Employee Benefit Plans - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Employee Benefit And Retirement Plans [Line Items]
 
 
 
Defined contribution plan, employer contribution
$ 17 
$ 16 
$ 6 
Postretirement Defined Benefit Plans, Liabilities
$ 10 
$ 11 
 
Maximum
 
 
 
Employee Benefit And Retirement Plans [Line Items]
 
 
 
Defined contribution plan, employer matching percentage
6.00% 
 
 
If employee are 40 years or older [Member]
 
 
 
Employee Benefit And Retirement Plans [Line Items]
 
 
 
Non matching employer contribution under defined benefit contribution plan
8.00% 
 
 
If employees are under age 40 [Member]
 
 
 
Employee Benefit And Retirement Plans [Line Items]
 
 
 
Non matching employer contribution under defined benefit contribution plan
6.00% 
 
 
Stock-Based Compensation - Additional Information (Detail) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Stock Based Compensation Activity [Line Items]
 
 
 
Common stock share authorized
2,000,000,000 
2,000,000,000 
 
Employee stock purchase plan purchase price first offering start date
Mar. 01, 2012 
 
 
Employee stock purchase plan purchase price first offering end date
Jun. 30, 2012 
 
 
Stock option exercisable period
3 years 
 
 
Stock option term
10 years 
 
 
Restricted stock units vesting period
3 years 
 
 
Unrecognized stock based compensation
$ 41 
 
 
Value of stock option exercised during year
13 
5 
5 
Cash received from stock option exercises
14 
4 
2 
Unearned grant expected to be recognized in period
 
 
3 years 
Minimum
 
 
 
Stock Based Compensation Activity [Line Items]
 
 
 
Range of vested shares of original grant amount
0.00% 
 
 
Maximum
 
 
 
Stock Based Compensation Activity [Line Items]
 
 
 
Range of vested shares of original grant amount
200.00% 
 
 
Nonvested Restricted Stock Units
 
 
 
Stock Based Compensation Activity [Line Items]
 
 
 
Performance based share granted, percent of nonvested restricted stock units outstanding
15.00% 
 
 
Administrative expenses
 
 
 
Stock Based Compensation Activity [Line Items]
 
 
 
Stock based compensation expense
35 
31 
28 
Stock Options
 
 
 
Stock Based Compensation Activity [Line Items]
 
 
 
Unrecognized stock based compensation
1 
 
 
Unrecognized stock based compensation, weighted average period of recognition
1 year 9 months 18 days 
 
 
Restricted Stock Units
 
 
 
Stock Based Compensation Activity [Line Items]
 
 
 
Unrecognized stock based compensation
$ 40 
 
 
Two Thousand Thirteen Incentive Plan [Member]
 
 
 
Stock Based Compensation Activity [Line Items]
 
 
 
Common stock share authorized
19,800,000 
 
 
Discount allowed on employee stock purchase plan
15.00% 
 
 
Number of share purchased under stock option plan
124,000 
 
 
Stock option plan, average purchase price
$ 12.56 
 
 
Two Thousand Thirteen Incentive Plan [Member] |
Maximum
 
 
 
Stock Based Compensation Activity [Line Items]
 
 
 
Number of share available for purchase under stock option plan
1,000,000 
 
 
Stock-Based Compensation - Summary of Stock Option Activity and Related Information (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Option Outstanding
 
Beginning Balance (in shares)
4.1 
Granted (in shares)
0.4 
Exercised (in shares)
(1.3)
Forfeited (in shares)
(0.1)
Ending Balance (in shares)
3.1 
Exercisable at end of period (in shares)
2.7 
Weighted Average Exercise price
 
Beginning Balance (in dollars per share)
$ 13.27 
Granted (in dollars per share)
$ 19.03 
Exercised (in dollars per share)
$ 11.11 
Forfeited (in dollars per share)
$ 15.39 
Ending Balance (in dollars per share)
$ 14.80 
Exercisable at end of period (in dollars per share)
$ 14.26 
Aggregate Intrinsic value
 
Beginning Balance
$ 29 
Ending Balance
2 
Exercisable at end of period
$ 2 
Stock-Based Compensation - Summary of Stock Option Activity and Related Information - Additional Information (Detail) (Williams Employees, USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Williams Employees
 
 
Schedule Of Stock Options [Line Items]
 
 
Share held by Williams' employees
137 
344 
Weighted average price of share held by Williams' employee
$ 10.64 
$ 9.24 
Stock-Based Compensation - Summary of Stock Option Outstanding and Exercisable (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
 
 
 
Range of Exercise Prices, Lower Limit
$ 16.46 
$ 20.21 
$ 16.46 
Range of Exercise Prices, Upper Limit
$ 21.81 
$ 20.97 
$ 20.97 
Options outstanding (in shares)
3.1 
4.1 
 
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)
$ 14.80 
$ 13.27 
 
Options Outstanding Weighted- Average Remaining Contractual Life (Years)
5 years 
 
 
Options exercisable (in shares)
2.7 
 
 
Options exercisable, Weighted- Average Exercise Price (in dollars per share)
$ 14.26 
 
 
Options exercisable, Weighted- Average Remaining Contractual Life (Years)
4 years 4 months 24 days 
 
 
$ 6.02 to $10.68
 
 
 
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
 
 
 
Range of Exercise Prices, Lower Limit
$ 6.02 
 
 
Range of Exercise Prices, Upper Limit
$ 10.68 
 
 
Options outstanding (in shares)
0.5 
 
 
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)
$ 7.59 
 
 
Options Outstanding Weighted- Average Remaining Contractual Life (Years)
2 years 9 months 18 days 
 
 
Options exercisable (in shares)
0.5 
 
 
Options exercisable, Weighted- Average Exercise Price (in dollars per share)
$ 7.59 
 
 
Options exercisable, Weighted- Average Remaining Contractual Life (Years)
2 years 9 months 18 days 
 
 
$11.32 to $13.46
 
 
 
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
 
 
 
Range of Exercise Prices, Lower Limit
$ 11.32 
 
 
Range of Exercise Prices, Upper Limit
$ 13.46 
 
 
Options outstanding (in shares)
0.6 
 
 
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)
$ 11.82 
 
 
Options Outstanding Weighted- Average Remaining Contractual Life (Years)
4 years 
 
 
Options exercisable (in shares)
0.6 
 
 
Options exercisable, Weighted- Average Exercise Price (in dollars per share)
$ 11.82 
 
 
Options exercisable, Weighted- Average Remaining Contractual Life (Years)
4 years 
 
 
$14.41 to $18.23
 
 
 
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
 
 
 
Range of Exercise Prices, Lower Limit
$ 14.41 
 
 
Range of Exercise Prices, Upper Limit
$ 18.23 
 
 
Options outstanding (in shares)
1.5 
 
 
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)
$ 16.39 
 
 
Options Outstanding Weighted- Average Remaining Contractual Life (Years)
6 years 1 month 6 days 
 
 
Options exercisable (in shares)
1.2 
 
 
Options exercisable, Weighted- Average Exercise Price (in dollars per share)
$ 16.36 
 
 
Options exercisable, Weighted- Average Remaining Contractual Life (Years)
5 years 7 months 6 days 
 
 
$19.95 to $21.81
 
 
 
Schedule Of Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding By Exercise Price [Line Items]
 
 
 
Range of Exercise Prices, Lower Limit
$ 19.95 
 
 
Range of Exercise Prices, Upper Limit
$ 21.81 
 
 
Options outstanding (in shares)
0.5 
 
 
Options Outstanding, Weighted- Average Exercise Price (in dollars per share)
$ 20.61 
 
 
Options Outstanding Weighted- Average Remaining Contractual Life (Years)
5 years 
 
 
Options exercisable (in shares)
0.4 
 
 
Options exercisable, Weighted- Average Exercise Price (in dollars per share)
$ 20.24 
 
 
Options exercisable, Weighted- Average Remaining Contractual Life (Years)
3 years 2 months 12 days 
 
 
Stock-Based Compensation - Estimated Fair Value at Date of Grant of Options for Common Stock and Date of Conversion for Awards using Black Scholes Option Pricing Model (Detail)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
 
 
 
Weighted-average or grant date fair value of options granted
$ 18.94 
$ 6.04 
$ 7.79 
Dividend yield
0.00% 
0.00% 
0.00% 
Volatility
43.00% 
42.80% 
43.80% 
Risk-free interest rate
1.85% 
1.06% 
1.17% 
Expected life
5 years 10 months 24 days 
6 years 
6 years 
Stock-Based Compensation - Summary of Nonvested Restricted Stock Unit Activity and Related Information (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Nonvested Shares
 
Beginning Balance
5.2 
Granted
2.5 
Forfeited
(0.7)
Vested
(1.9)
Ending balance
5.1 
Weighted-Average Fair Value
 
Nonvested, Beginning Balance
$ 16.97 1
Granted
$ 18.37 1
Forfeited
$ 16.92 1
Vested
$ 16.92 1
Nonvested, Ending Balance
$ 17.58 1
Stock-Based Compensation - Other Restricted Stock Unit (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Equity Instruments Other Than Options Restricted Stock And Stock Units [Line Items]
 
 
 
Weighted-average grant date fair value of restricted stock units granted during the year, per share
$ 18.37 1
 
 
Restricted Stock Units
 
 
 
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Equity Instruments Other Than Options Restricted Stock And Stock Units [Line Items]
 
 
 
Weighted-average grant date fair value of restricted stock units granted during the year, per share
$ 18.37 
$ 14.97 
$ 17.35 
Total fair value of restricted stock units vested during the year (millions)
$ 33 
$ 18 
$ 14 
Stockholders' Equity - Additional Information (Detail) (USD $)
12 Months Ended
Dec. 31, 2014
Vote
Dec. 31, 2013
Dec. 31, 2012
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
 
 
 
Number of votes per share for common stockholders
1 
 
 
Dividends declared (in dollars per share)
$ 0 
$ 0 
$ 0 
Dividends paid (in dollars per share)
$ 0 
$ 0 
$ 0 
Common Stock Subject to Mandatory Redemption
 
 
 
Financial Instruments Subject to Mandatory Redemption by Settlement Terms [Line Items]
 
 
 
Shares subject to redemption
0 
 
 
Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Long-term debt
$ 2,218 1
$ 1,938 1
Energy Related Derivative
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Energy derivative assets
536 
57 
Energy derivative liabilities
42 
122 
Level 1 |
Energy Related Derivative
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Energy derivative assets
14 
30 
Energy derivative liabilities
32 
83 
Level 2
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Long-term debt
2,218 1
1,938 1
Level 2 |
Energy Related Derivative
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Energy derivative assets
517 
26 
Energy derivative liabilities
10 
38 
Level 3 |
Energy Related Derivative
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Energy derivative assets
5 
1 
Energy derivative liabilities
$ 0 
$ 1 
Fair Value Measurements - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Percentage of net fair value of derivatives portfolio expiring
100.00% 
 
Expiry of net fair value of derivatives portfolio
24 months 
 
Long-term Debt, Excluding Current Maturities
$ 2,280 
$ 1,910 
Fair Value Measurements - Level 3 Fair Value Measurements Using Significant Unobservable Inputs (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
Beginning balance
$ 0 
$ (1)
$ 1 
Realized and unrealized gains (losses) included in income (loss) from continuing operations
5 
(2)
3 
Realized and unrealized gains (losses) included in other comprehensive income (loss)
0 
0 
0 
Purchases, issuances, and settlements
0 
3 
(5)
Transfers out of Level 3
0 
0 
0 
Ending balance
5 
0 
(1)
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31
$ 5 
$ (1)
$ (1)
Fair Value Measurements - Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Fair Value Disclosures [Abstract]
 
 
 
Impairment of producing properties and costs of acquired unproved reserves (Note 4)
$ 20 1
$ 1,055 2
$ 225 3
Unproved leasehold
0 
317 2
0 
Equity method investment (Note 4)
$ 0 
$ 20 2
$ 0 
[1] As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:•$11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.•$9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties.
[2] As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.
[3] As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:•$102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
Fair Value Measurements - Impairments Associated with Certain Assets Measured at Fair Value on Nonrecurring Basis within Level 3 of Fair Value Hierarchy - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Fair value of producing properties and costs of acquired unproved reserves
$ 11 
$ 365 
$ 351 
Weighted average natural gas price
4.34 
3.63 
3.01 
Unproved leasehold property impairment, amortization and expiration
74 
402 
58 
Unproved Leasehold Property Impairment
0 
317 1
0 
Equity method investment (Note 4)
0 
20 1
0 
Asset Impairment Charges Including Discontinued Operations
20 
1,392 
225 
Probable Reserves |
Unproved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Percentage of discount rate after-tax
 
 
13.00% 
Possible Reserves |
Unproved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Percentage of discount rate after-tax
 
 
15.00% 
Green River Basin
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Impairment Charge
11 
 
 
Green River Basin |
Proved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Impairment Charge
 
 
48 
Weighted average natural gas price
4.77 
 
5.87 
Percentage of discount rate after-tax
 
 
11.00% 
Green River Basin |
Producing Properties [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Percentage of discount rate after-tax
9.00% 
 
 
Green River Basin |
Undeveloped Properties [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Percentage of discount rate after-tax
11.00% 
 
 
Green River Basin |
Minimum |
Proved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Proved reserve quantities of gas equivalent
23,000,000 
 
29,000,000 
Appalachian Basin
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Impairment Charge Including Equity Method Investment
 
792 
 
Impairment Charge
 
772 
 
Unproved leasehold property impairment, amortization and expiration
 
317 
 
Appalachian Basin |
Proved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Weighted average natural gas price
 
3.60 
 
Percentage of discount rate after-tax
 
11.00% 
 
Appalachian Basin |
Minimum |
Proved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Proved reserve quantities of gas equivalent
 
299,000,000 
 
Powder River Basin
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Impairment Charge
 
107 
102 
Impairment of producing properties and costs of acquired unproved reserves
 
85 
 
Powder River Basin |
Proved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Weighted average natural gas price
 
3.53 
 
Percentage of discount rate after-tax
 
11.00% 
 
Powder River Basin |
Probable Reserves |
Unproved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Percentage of discount rate after-tax
 
15.00% 
 
Powder River Basin |
Possible Reserves |
Unproved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Percentage of discount rate after-tax
 
18.00% 
 
Powder River Basin |
Minimum |
Proved Properties
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Proved reserve quantities of gas equivalent
 
294,000,000 
 
Piceance
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Impairment of producing properties and costs of acquired unproved reserves
 
88 
75 
Piceance |
Probable Reserves
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Percentage of discount rate after-tax
 
13.00% 
 
Piceance |
Possible Reserves
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Percentage of discount rate after-tax
 
15.00% 
 
Other Member
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Impairment of producing properties and costs of acquired unproved reserves
$ 9 
 
 
[1] As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.
Derivatives and Concentration of Credit Risk - Derivative Volumes that are Economic Hedges of Production Volumes as well as Notional Amounts of Net Long (Short) Positions which do not Represent Economic Hedges of Production (Detail) (Short)
12 Months Ended
Dec. 31, 2014
2015 [Member] |
Derivatives related to production |
Crude Oil Commodity Contract One |
Fixed Priced Swaps |
WTI
 
Derivative [Line Items]
 
Notional Volume
(20,236)1 2
Underlying, Derivative
94.88 1 3
2015 [Member] |
Derivatives related to production |
Crude Oil Commodity Contract Two |
Swaptions |
WTI
 
Derivative [Line Items]
 
Notional Volume
(882)1 2
Underlying, Derivative
97.29 1 3
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract One |
Fixed Priced Swaps |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
(442,000)1 2
Underlying, Derivative
4.10 1 3
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Three |
Costless Collar |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
(50,000)1 2
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Three |
Costless Collar |
Henry Hub |
Minimum
 
Derivative [Line Items]
 
Underlying, Derivative
4.00 
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Three |
Costless Collar |
Henry Hub |
Maximum
 
Derivative [Line Items]
 
Underlying, Derivative
4.50 1 4
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Five |
Basis Swap |
NGPL [Member]
 
Derivative [Line Items]
 
Notional Volume
(13,000)1 2
Underlying, Derivative
(0.16)1 3
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Six |
Basis Swap |
Rockies
 
Derivative [Line Items]
 
Notional Volume
(150,000)1 2
Underlying, Derivative
(0.11)1 3
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Seven |
Basis Swap |
San Juan [Member]
 
Derivative [Line Items]
 
Notional Volume
(85,000)1 2
Underlying, Derivative
(0.10)1 3
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Seven |
Basis Swap |
Southern California Gas [Member]
 
Derivative [Line Items]
 
Notional Volume
(20,000)1 2
Underlying, Derivative
0.18 1 3
2015 [Member] |
Derivatives primarily related to storage and transportation |
Natural Gas Commodity Contract Two |
Basis Swap |
Multiple Location
 
Derivative [Line Items]
 
Notional Volume
(3,000)4 5 6
2015 [Member] |
Derivatives primarily related to storage and transportation |
Natural Gas Commodity Contract Three |
Index |
Multiple Location
 
Derivative [Line Items]
 
Notional Volume
(118,000)4 5 6
2016 [Member] |
Derivatives related to production |
Crude Oil Commodity Contract Two |
Swaptions |
WTI
 
Derivative [Line Items]
 
Notional Volume
(5,250)1 2
Underlying, Derivative
97.55 1 3
2016 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Eight |
Fixed Priced Swaps |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
(200,000)1 2
Underlying, Derivative
3.98 1 3
2016 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Nine |
Swaptions |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
(90,000)1 2
Underlying, Derivative
4.23 1 3
2016 [Member] |
Derivatives primarily related to storage and transportation |
Natural Gas Commodity Contract Five |
Index |
Multiple Location
 
Derivative [Line Items]
 
Notional Volume
(70,000)4 5 6
2017 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Nine |
Swaptions |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
(65,000)1 2
Underlying, Derivative
4.19 1 3
2017 [Member] |
Derivatives primarily related to storage and transportation |
Natural Gas Commodity Contract Six |
Index |
Multiple Location
 
Derivative [Line Items]
 
Notional Volume
(70,000)4 5 6
2018 and beyond [Member] |
Derivatives primarily related to storage and transportation |
Natural Gas Commodity Contract Seven |
Index |
Multiple Location
 
Derivative [Line Items]
 
Notional Volume
(379,000)4 5 6
Derivatives and Concentration of Credit Risk - Additional Information (Detail) (USD $)
3 Months Ended 12 Months Ended 12 Months Ended
Mar. 31, 2012
Dec. 31, 2014
Dec. 31, 2012
Dec. 31, 2013
Dec. 31, 2014
Domestic Segment
BP Energy
Dec. 31, 2013
Domestic Segment
BP Energy
Dec. 31, 2012
Domestic Segment
BP Energy
Dec. 31, 2014
Domestic Segment
Southern California Gas
Dec. 31, 2013
Domestic Segment
Southern California Gas
Dec. 31, 2012
Domestic Segment
Williams [Member]
Dec. 31, 2014
Maximum
Dec. 31, 2013
Maximum
Derivative [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net
 
$ 0 
 
 
 
 
 
 
 
 
 
 
Collateral posted to derivative
 
26,000,000 
 
71,000,000 
 
 
 
 
 
 
 
 
Initial margin
 
9,000,000 
 
19,000,000 
 
 
 
 
 
 
 
 
Maintenance margin
 
17,000,000 
 
52,000,000 
 
 
 
 
 
 
 
 
Net derivative liability position
 
17,000,000 
 
72,000,000 
 
 
 
 
 
 
 
 
Reduction in derivative liabilities
 
 
 
 
 
 
 
 
 
 
1,000,000 
1,000,000 
Additional collateral posted
 
1,000,000 
 
20,000,000 
 
 
 
 
 
 
 
 
Unrealized gains recognized for hedge transactions
15,000,000 
 
33,000,000 
 
 
 
 
 
 
 
 
 
Unearned Non Cash Stock Based Compensation Expected To Recognize As Expense Over Period
 
 
3 years 
 
 
 
 
 
 
 
 
 
Net gains reclassified into earnings within the next year
 
 
3,000,000 
 
 
 
 
 
 
 
 
 
Net of income tax provision
 
 
2,000,000 
 
 
 
 
 
 
 
 
 
Net credit exposure percentage
 
96.00% 
 
 
 
 
 
 
 
 
 
 
Collateral support
 
$ 32,000,000 
 
 
 
 
 
 
 
 
 
 
Percentage of consolidated revenue
 
 
 
 
13.00% 
16.00% 
11.00% 
8.00% 
11.00% 
14.00% 
 
 
Derivatives and Concentration of Credit Risk - Fair Value of Energy Commodity Derivatives (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Derivatives, Fair Value [Line Items]
 
 
Total derivatives, Assets
$ 536 
$ 57 
Total derivatives, Liabilities
42 
122 
Not Designated as Hedging Instrument
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivatives, Assets
536 
57 
Total derivatives, Liabilities
42 
122 
Not Designated as Hedging Instrument |
Derivatives related to production
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivatives, Assets
517 
26 
Total derivatives, Liabilities
10 
39 
Not Designated as Hedging Instrument |
Derivatives Related to Physical Marketing Agreements
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivatives, Assets
19 
31 
Total derivatives, Liabilities
$ 32 
$ 83 
Derivatives and Concentration of Credit Risk - Pre-Tax Gains and Losses for Energy Commodity Derivatives Designated as Cash Flow Hedges, as Recognized in Accumulated Other Comprehensive Income or Revenues (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)
 
$ 5 
$ 434 
Cash Flow Hedging |
Accumulated Other Comprehensive Income
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Net gain recognized in other comprehensive income (loss) (effective portion)
0 
0 
90 
Cash Flow Hedging |
Revenues
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)
$ 0 1
$ 5 1
$ 434 1
Derivatives and Concentration of Credit Risk - Offsetting of Derivative Assets and Liabilities (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Derivative Asset [Abstract]
 
 
Gross Amount Presented on Balance Sheet
$ 536 
$ 57 
Netting Adjustment
(25)1
(50)1
Cash Collateral Posted(Received)
0 
0 
Net Amount
511 
7 
Derivative Liability [Abstract]
 
 
Gross Amount Presented on Balance Sheet
(42)
(122)
Netting adjustment
25 1
50 1
Cash Collateral Posted(Received)
17 
52 
Net Amount
$ 0 
$ (20)
Derivatives and Concentration of Credit Risk - Concentration of Receivables, Net of Allowances, by Product or Service (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Receivables [Line Items]
 
 
Account receivables
$ 459 
$ 518 
Sale of natural gas and related products and services
 
 
Receivables [Line Items]
 
 
Account receivables
340 
339 
Joint interest owners
 
 
Receivables [Line Items]
 
 
Account receivables
106 
168 
Other
 
 
Receivables [Line Items]
 
 
Account receivables
$ 13 
$ 11 
Derivatives and Concentration of Credit Risk - Gross and Net Credit Exposure from Derivative Contracts (Detail) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Credit Exposure From Derivatives [Line Items]
 
Total gross credit exposure from derivative contracts before credit reserve
$ 537 
Gross credit reserves
(1)
Gross credit exposure from derivatives
536 
Total net credit exposure from derivative contracts before credit reserve
512 
Net credit reserves
(1)
Net credit exposure from derivatives
511 
Gas And Electric Utilities And Integrated Oil And Gas Companies [Member]
 
Credit Exposure From Derivatives [Line Items]
 
Total gross credit exposure from derivative contracts before credit reserve
4 
Total net credit exposure from derivative contracts before credit reserve
4 
Financial institutions
 
Credit Exposure From Derivatives [Line Items]
 
Total gross credit exposure from derivative contracts before credit reserve
533 1
Total net credit exposure from derivative contracts before credit reserve
$ 508 1
Derivatives and Concentration of Credit Risk - Gross and Net Credit Exposure from Derivative Contracts - Additional Information (Detail)
12 Months Ended
Dec. 31, 2014
Standard & Poor's
 
Credit Exposure From Derivatives [Line Items]
 
Counterparties credit rating in investment grade
BBB- 
Moody's Investors Service
 
Credit Exposure From Derivatives [Line Items]
 
Counterparties credit rating in investment grade
Baa3 
Derivatives and Concentration of Credit Risk Derivatives and concentration of credit risk Gain (Loss) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
DerivativeGainLoss [Line Items]
 
 
 
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net
$ 434 
$ (124)
$ 78 
Energy Related Derivative
 
 
 
DerivativeGainLoss [Line Items]
 
 
 
Payment Made for Settlement of Derivatives
4 
11 
 
Payment Received for Settlement of Derivatives
 
 
29 
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net
515 1
(57)1
66 1
Derivatives Related to Physical Marketing Agreements
 
 
 
DerivativeGainLoss [Line Items]
 
 
 
Payment Made for Settlement of Derivatives
120 
6 
 
Payment Received for Settlement of Derivatives
 
 
17 
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net
$ (81)2
$ (67)2
$ 12 2
Quarterly Financial Data Quarterly Financial Data-Summarized Quarterly Financial Data (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Quarterly Financial Data [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 1,125 
$ 747 
$ 727 
$ 894 
$ 576 
$ 581 
$ 722 
$ 552 
$ 3,493 
$ 2,431 
$ 2,900 
Operating costs and expenses
656 
570 
659 
783 
1,024 
621 
612 
634 
 
 
 
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest
227 
46 
(144)
0 
(890)
(105)
6 
(115)
129 
(1,104)
(174)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
(8)
20 
11 
19 
(94)
(11)
16 
2 
42 
(87)
(37)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest
219 
66 
(133)
19 
(984)
(116)
22 
(113)
171 
(1,191)
(211)
Income (Loss) from Continuing Operations Attributable to WPX
227 
46 
(144)
0 
(878)
(105)
6 
(115)
129 
(1,092)
(174)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX
(8)
16 
9 
18 
(95)
(9)
12 
(1)
35 
(93)
(49)
Net Income (Loss) Attributable to Parent
$ 219 
$ 62 
$ (135)
$ 18 
$ (973)
$ (114)
$ 18 
$ (116)
$ 164 
$ (1,185)
$ (223)
Income (Loss) from Continuing Operations, Per Basic Share
$ 1.11 
$ 0.23 
$ (0.71)
$ 0.00 
 
 
 
 
$ 0.63 
$ (5.45)
$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share
$ (0.03)
$ 0.07 
$ 0.05 
$ 0.09 
 
 
 
 
$ 0.18 
$ (0.46)
$ (0.25)
Earnings Per Share, Basic
$ 1.08 
$ 0.30 
$ (0.66)
$ 0.09 
 
 
 
 
$ 0.81 
$ (5.91)
$ (1.12)
Income (Loss) from Continuing Operations, Per Diluted Share
$ 1.10 
$ 0.23 
$ (0.71)
$ 0.00 
 
 
 
 
$ 0.62 
$ (5.45)
$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share
$ (0.04)
$ 0.07 
$ 0.05 
$ 0.09 
 
 
 
 
$ 0.18 
$ (0.46)
$ (0.25)
Earnings Per Share, Diluted
$ 1.06 
$ 0.30 
$ (0.66)
$ 0.09 
 
 
 
 
$ 0.80 
$ (5.91)
$ (1.12)
Income (Loss) from Continuing Operations, Per Basic and Diluted Share
 
 
 
 
$ (4.37)
$ (0.52)
$ 0.03 
$ (0.57)
 
 
 
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share
 
 
 
 
$ (0.48)
$ (0.05)
$ 0.06 
$ (0.01)
 
 
 
Earnings Per Share, Basic and Diluted
 
 
 
 
$ (4.85)
$ (0.57)
$ 0.09 
$ (0.58)
 
 
 
Quarterly Financial Data -Adjusted Quarterly Financial Data (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Quarterly Financial Data Adjustments [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 1,125 
$ 747 
$ 727 
$ 894 
$ 576 
$ 581 
$ 722 
$ 552 
$ 3,493 
$ 2,431 
$ 2,900 
Operating costs and expenses
656 
570 
659 
783 
1,024 
621 
612 
634 
 
 
 
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest
227 
46 
(144)
0 
(890)
(105)
6 
(115)
129 
(1,104)
(174)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
(8)
20 
11 
19 
(94)
(11)
16 
2 
42 
(87)
(37)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest
219 
66 
(133)
19 
(984)
(116)
22 
(113)
171 
(1,191)
(211)
Income (Loss) from Continuing Operations Attributable to WPX
227 
46 
(144)
0 
(878)
(105)
6 
(115)
129 
(1,092)
(174)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX
(8)
16 
9 
18 
(95)
(9)
12 
(1)
35 
(93)
(49)
Net Income (Loss) Attributable to Parent
219 
62 
(135)
18 
(973)
(114)
18 
(116)
164 
(1,185)
(223)
Income (Loss) from Continuing Operations, Per Basic Share
$ 1.11 
$ 0.23 
$ (0.71)
$ 0.00 
 
 
 
 
$ 0.63 
$ (5.45)
$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share
$ (0.03)
$ 0.07 
$ 0.05 
$ 0.09 
 
 
 
 
$ 0.18 
$ (0.46)
$ (0.25)
Earnings Per Share, Basic
$ 1.08 
$ 0.30 
$ (0.66)
$ 0.09 
 
 
 
 
$ 0.81 
$ (5.91)
$ (1.12)
Income (Loss) from Continuing Operations, Per Diluted Share
$ 1.10 
$ 0.23 
$ (0.71)
$ 0.00 
 
 
 
 
$ 0.62 
$ (5.45)
$ (0.87)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share
$ (0.04)
$ 0.07 
$ 0.05 
$ 0.09 
 
 
 
 
$ 0.18 
$ (0.46)
$ (0.25)
Earnings Per Share, Diluted
$ 1.06 
$ 0.30 
$ (0.66)
$ 0.09 
 
 
 
 
$ 0.80 
$ (5.91)
$ (1.12)
Income (Loss) from Continuing Operations, Per Basic and Diluted Share
 
 
 
 
$ (4.37)
$ (0.52)
$ 0.03 
$ (0.57)
 
 
 
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share
 
 
 
 
$ (0.48)
$ (0.05)
$ 0.06 
$ (0.01)
 
 
 
Earnings Per Share, Basic and Diluted
 
 
 
 
$ (4.85)
$ (0.57)
$ 0.09 
$ (0.58)
 
 
 
Quarterly [Member]
 
 
 
 
 
 
 
 
 
 
 
Quarterly Financial Data Adjustments [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
47 1
(87)
(93)
(81)
35 1
(93)
(79)
 
 
 
Operating costs and expenses
 
31 1
62 
(62)
(74)
22 1
(77)
(76)
 
 
 
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest
 
(15)1
(11)
(19)
94 
3 1
(16)
(2)
 
 
 
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
 
15 1
11 
19 
(94)
(3)1
16 
2 
 
 
 
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest
 
0 1
0 
0 
0 
0 1
0 
0 
 
 
 
Income (Loss) from Continuing Operations Attributable to WPX
 
(16)1
(9)
(18)
95 
9 1
(12)
1 
 
 
 
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX
 
16 1
9 
18 
(95)
(9)1
12 
(1)
 
 
 
Net Income (Loss) Attributable to Parent
 
$ 0 1
$ 0 
$ 0 
$ 0 
$ 0 1
$ 0 
$ 0 
 
 
 
Income (Loss) from Continuing Operations, Per Basic Share
 
$ (0.05)1
$ (0.05)
$ (0.09)
 
 
 
 
 
 
 
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share
 
$ 0.05 1
$ 0.05 
$ 0.09 
 
 
 
 
 
 
 
Earnings Per Share, Basic
 
$ 0.00 1
$ 0.00 
$ 0.00 
 
 
 
 
 
 
 
Income (Loss) from Continuing Operations, Per Diluted Share
 
$ (0.05)1
$ (0.05)
$ (0.09)
 
 
 
 
 
 
 
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share
 
$ 0.05 1
$ 0.05 
$ 0.09 
 
 
 
 
 
 
 
Earnings Per Share, Diluted
 
$ 0.00 1
$ 0.00 
$ 0.00 
 
 
 
 
 
 
 
Income (Loss) from Continuing Operations, Per Basic and Diluted Share
 
 
 
 
$ 0.48 
$ 0.01 1
$ (0.06)
$ 0.01 
 
 
 
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share
 
 
 
 
$ (0.48)
$ (0.01)1
$ 0.06 
$ (0.01)
 
 
 
Earnings Per Share, Basic and Diluted
 
 
 
 
$ 0.00 
$ 0.00 1
$ 0.00 
$ 0.00 
 
 
 
Quarterly Financial Data - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Quarterly Financial Data [Line Items]
 
 
 
 
 
 
 
 
Impairment Of Costs Of Producing Properties, Acquired Unproved Reserves, leasehold, and equity method investment
$ 87 
 
 
 
$ 1,178 
 
 
 
Proceeds from Sale of Other Assets
18 
 
 
 
 
 
 
 
Exploration Abandonment and Impairment Expense
 
22 
40 
 
 
 
 
 
Gas Management Expense, Other
 
 
11 
 
 
 
 
 
Deferred Other Tax Expense (Benefit)
9 
 
 
9 
 
 
 
 
Loss On Sale Of Working Interests
 
1 
195 
 
 
196 
0 
0 
Buyout of Transportation Agreement
 
 
 
 
9 
14 
 
 
Powder River Basin
 
 
 
 
 
 
 
 
Quarterly Financial Data [Line Items]
 
 
 
 
 
 
 
 
Impairment of producing properties and costs of acquired unproved reserves
 
 
 
 
 
 
85 
 
Kokopelli area of Piceance Basin
 
 
 
 
 
 
 
 
Quarterly Financial Data [Line Items]
 
 
 
 
 
 
 
 
Impairment of producing properties and costs of acquired unproved reserves
$ 69 
$ 19 
 
 
$ 19 
 
 
 
Supplemental Oil and Gas Disclosures - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Mcfe
Dec. 31, 2013
Mcfe
Dec. 31, 2012
Mcfe
Dec. 31, 2011
Mcfe
Supplementary Information [Line Items]
 
 
 
 
Proved Developed and Undeveloped Reserves, Net
300,000.0 
 
 
 
Equipment and facilities in support of oil and gas production excluded from capitalization
$ 385 
$ 328 
 
 
Equity earnings from the international equity method investee
1 
21 
1 
 
Impairment of oil and gas properties
20 1
1,055 2
225 3
 
Computation of natural gas reserves
Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. 
 
 
 
Weighted average natural gas price
4.34 
3.63 
3.01 
 
Weighted average oil per barrel price
83.62 
92.16 
82.32 
 
Discount rate
10.00% 
 
 
 
Powder River Basin
 
 
 
 
Supplementary Information [Line Items]
 
 
 
 
Operations representing total domestic and international proved reserves
5.00% 
 
 
 
International
 
 
 
 
Supplementary Information [Line Items]
 
 
 
 
Operations representing total domestic and international proved reserves
5.00% 
 
 
 
Appalachian Basin
 
 
 
 
Supplementary Information [Line Items]
 
 
 
 
Operations representing total domestic and international proved reserves
5.00% 
 
 
 
Impairment of oil and gas properties
$ 317 
 
 
 
Oil and Condensate Sales |
Domestic
 
 
 
 
Supplementary Information [Line Items]
 
 
 
 
Proved Developed and Undeveloped Reserves, Net
130.8 
102.9 
76.5 
47.1 
Oil and Condensate Sales |
San Juan [Member]
 
 
 
 
Supplementary Information [Line Items]
 
 
 
 
Proved Developed and Undeveloped Reserves, Net
28,000.0 
 
 
 
All products |
Domestic
 
 
 
 
Supplementary Information [Line Items]
 
 
 
 
Proved developed reserves, revisions
97,000 
133,000 
 
 
Proved undeveloped reserves, revisions
422,000 
44,000 
 
 
Additions due to added drill locations
189,000 
127,000 
225,000 
 
Additions due to new undeveloped locations
502,000 
407,000 
405,000 
 
Proved Developed And Undeveloped Reserves Net Equivalent
4,359,600 4
4,761,600 4
4,490,500 4
5,070,100 4
All products |
Powder River Basin
 
 
 
 
Supplementary Information [Line Items]
 
 
 
 
Proved Developed And Undeveloped Reserves Net Equivalent
200,000 4
244,600 4
235,900 4
 
[1] As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately $11 million:•$11 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 23.0 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.77 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of 9 percent and 11 percent.•$9 million of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties.
[2] As a result of our impairment assessment in 2013, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million:•$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$85 million impairment charge related to acquired unproved reserves in the Powder River Basin reported in discontinued operations. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.
[3] As a result of our impairment assessments in 2012, we recorded the following significant impairment charges, including those in discontinued operations, for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million:•$102 million of impairment charges related to acquired unproved reserves in the Powder River Basin reported in discontinued operations and $75 million of impairment charges related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
Supplemental Oil and Gas Disclosures - Capitalization Cost (Detail) (Domestic, USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Domestic
 
 
Capitalized Expedition Cost Related To Specific Assets [Line Items]
 
 
Proved Properties
$ 10,717 
$ 11,132 
Unproved properties
394 
324 
Total property costs
11,111 
11,456 
Accumulated depreciation, depletion and amortization and valuation provisions
(4,698)
(5,070)
Net capitalized costs
$ 6,413 
$ 6,386 
Supplemental Oil and Gas Disclosures - Cost Incurred (Detail) (Domestic, USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Domestic
 
 
 
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
 
 
 
Acquisition
$ 294 
$ 57 
$ 111 
Exploration
92 
104 
23 
Development
1,376 
939 
1,130 
Total costs incurred
$ 1,762 
$ 1,100 
$ 1,264 
Supplemental Oil and Gas Disclosures - Results of Operation (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
 
 
 
Impairment of certain natural gas properties
 
 
$ 20 1
$ 860 1
$ 123 1
Loss On Sale Of Working Interests
1 
195 
196 
0 
0 
Domestic
 
 
 
 
 
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
 
 
 
Revenues
 
 
2,454 
1,607 
1,939 
Net gain (loss) on derivatives not designated as hedges
 
 
515 
(57)
66 
Other revenues
 
 
8 
6 
7 
Lease and facility operating
 
 
244 
227 
202 
Gathering, processing and transportation
 
 
328 
350 
434 
Taxes other than income
 
 
126 
102 
68 
Exploration
 
 
173 
423 
71 
Depreciation, depletion and amortization
 
 
810 
858 
884 
Impairment of certain natural gas properties
 
 
15 
772 
48 
Impairment of costs of acquired unproved reserves
 
 
5 
88 
75 
Loss On Sale Of Working Interests
 
 
196 
0 
0 
General and administrative
 
 
264 
262 
259 
Other (income) expense
 
 
12 
12 
16 
Total costs
 
 
2,173 
3,094 
2,057 
Results of operations
 
 
281 
(1,487)
(118)
Provision (benefit) for income taxes
 
 
103 
(543)
(43)
Exploration and production net income (loss)
 
 
178 
(944)
(75)
Domestic |
Natural Gas
 
 
 
 
 
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
 
 
 
Revenues
 
 
1,002 
896 
1,193 
Domestic |
Oil and Condensate Sales
 
 
 
 
 
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
 
 
 
Revenues
 
 
724 
534 
376 
Domestic |
Natural Gas Liquids
 
 
 
 
 
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
 
 
 
Revenues
 
 
$ 205 
$ 228 
$ 297 
Supplemental Oil and Gas Disclosures - Proved Reserves (Detail)
12 Months Ended
Dec. 31, 2014
MMcf
Dec. 31, 2013
MMcf
Dec. 31, 2012
MMcf
Supplementary Information [Line Items]
 
 
 
Proved reserves ending balance
300,000 
 
 
Domestic |
Natural Gas
 
 
 
Supplementary Information [Line Items]
 
 
 
Proved reserves beginning balance
3,629,800 
3,369,100 
3,982,900 
Revisions
(198,300)
308,300 
(404,800)
Purchases
(6,000)
 
(5,800)
Divestitures
(314,600)
(200)
(217,000)
Extensions and discoveries
362,100 
312,000 
409,200 
Production
(335,400)
(359,400)
(407,000)
Proved reserves ending balance
3,149,600 
3,629,800 
3,369,100 
Proved developed reserves
2,090,000 
2,265,200 
2,170,700 
Proved undeveloped reserves
1,059,600 
1,364,600 
1,198,400 
Domestic |
Oil and Condensate Sales
 
 
 
Supplementary Information [Line Items]
 
 
 
Proved reserves beginning balance
102.9 
76.5 
47.1 
Revisions
(7.7)
3.5 
5.6 
Purchases
(4.2)
 
0.0 
Divestitures
(1.8)
0.0 
(0.3)
Extensions and discoveries
42.4 
28.8 
28.5 
Production
(9.2)
(5.9)
(4.4)
Proved reserves ending balance
130.8 
102.9 
76.5 
Proved developed reserves
60.0 
36.8 
23.7 
Proved undeveloped reserves
70.8 
66.1 
52.8 
Domestic |
Natural Gas Liquids
 
 
 
Supplementary Information [Line Items]
 
 
 
Proved reserves beginning balance
85.7 
110.4 
134.0 
Revisions
(13.4)
(25.4)
(21.1)
Purchases
(0.8)
0.0 
0.0 
Divestitures
(8.5)
 
(1.0)
Extensions and discoveries
12.5 
8.1 
8.9 
Production
(6.3)
(7.4)
(10.4)
Proved reserves ending balance
70.8 
85.7 
110.4 
Proved developed reserves
43.9 
48.6 
64.9 
Proved undeveloped reserves
26.9 
37.1 
45.5 
Domestic |
All products
 
 
 
Supplementary Information [Line Items]
 
 
 
Proved reserves beginning balance
4,761,600 1
4,490,500 1
5,070,100 1
Revisions
(324,800)1
177,200 1
(498,600)1
Purchases
36,500 1
 
5,800 1
Divestitures
(376,600)1
(500)1
(224,800)1
Extensions and discoveries
691,300 1
533,800 1
633,800 1
Production
(428,400)1
(439,400)1
(495,800)1
Proved reserves ending balance
4,359,600 1
4,761,600 1
4,490,500 1
Proved developed reserves
2,713,800 1
2,777,700 1
2,702,600 1
Proved undeveloped reserves
1,645,800 1
1,983,900 1
1,787,900 1
Supplemental Oil and Gas Disclosures - Proved Reserves - Additional Information (Detail)
Conversion Rate Of Oil And Ngl Quantities
Oil and natural gas liquids were converted to Bcfe using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.
Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Detail) (Domestic, USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Domestic
 
 
 
 
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
 
 
 
 
Future cash inflows
$ 26,444 
$ 24,547 
 
 
Future production costs
12,641 
12,148 
 
 
Future development costs
3,426 
3,789 
 
 
Future income tax provisions
2,519 
2,147 
 
 
Future net cash flows
7,858 
6,463 
 
 
Less 10 percent annual discount for estimated timing of cash flows
(3,975)
(3,499)
 
 
Standardized measure of discounted future net cash inflows
$ 3,883 
$ 2,964 
$ 1,949 
$ 3,591 
Supplemental Oil and Gas Disclosures - Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) (Domestic, USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Domestic
 
 
 
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
 
 
 
Standardized measure of discounted future net cash flows beginning of period
$ 2,964 
$ 1,949 
$ 3,591 
Sales of oil and gas produced, net of operating costs
(1,324)
(1,040)
(778)
Net change in prices and production costs
303 
1,198 
(3,601)
Extensions, discoveries and improved recovery, less estimated future costs
1,761 
1,282 
1,154 
Development costs incurred during year
592 
414 
333 
Changes in estimated future development costs
143 
(736)
50 
Purchase of reserves in place, less estimated future costs
147 
0 
4 
Sale of reserves in place, loss estimated future costs
(391)
(3)
(272)
Revisions of previous quantity estimates
(536)
239 
(232)
Accretion of discount
383 
225 
481 
Net change in income taxes
(142)
(540)
1,194 
Other
(17)
(24)
25 
Net changes
919 
1,015 
(1,642)
Standardized measure of discounted future net cash flows end of period
$ 3,883 
$ 2,964 
$ 1,949 
Schedule II - Valuation And Qualifying Accounts (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Allowance for doubtful accounts - accounts and notes receivable
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Beginning Balance
$ 7 1
$ 11 1
$ 13 1
Charged (Credited) to Costs and Expenses
0 1
(3)1
(2)1
Deductions
(1)1
(1)1
0 1
Ending Balance
6 1
7 1
11 1
Deferred tax asset valuation allowance
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Beginning Balance
102 2
19 2
16 2
Charged (Credited) to Costs and Expenses
(1)2
80 2
3 2
Other
17 2
3 2
 
Deductions
0 2
0 2
0 2
Ending Balance
118 2
102 2
19 2
Price-risk management credit reserves-assets
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Beginning Balance
0 1 3
 
 
Charged (Credited) to Costs and Expenses
0 1 3
 
 
Other
1 1 3
 
 
Deductions
0 1 3
 
 
Ending Balance
$ 1 1 3