WPX ENERGY, INC., 10-Q filed on 11/5/2014
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2014
Nov. 4, 2014
Document Documentand Entity Information [Abstract]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Sep. 30, 2014 
 
Document Fiscal Year Focus
2014 
 
Document Fiscal Period Focus
Q3 
 
Trading Symbol
WPX 
 
Entity Registrant Name
WPX ENERGY, INC. 
 
Entity Central Index Key
0001518832 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
203,370,114 
Consolidated Balance Sheet (Unaudited) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Current assets:
 
 
Cash and cash equivalents
$ 65 
$ 99 
Accounts receivable, net of allowance of $6 million at September 30, 2014 and $7 million at December 31, 2013
465 
536 
Deferred income taxes
31 
49 
Derivative assets, current
107 
50 
Inventories
70 
71 
Margin deposits
52 
71 
Assets classified as held for sale, current
184 
1 
Other
31 
45 
Total current assets
1,005 
922 
Investments
135 
129 
Properties and equipment (successful efforts method of accounting)
11,993 
12,519 
Less—accumulated depreciation, depletion and amortization
(4,956)
(5,445)
Properties and equipment, net
7,037 
7,074 
Derivative assets, noncurrent
22 
7 
Other noncurrent assets
45 
297 
Total assets
8,244 
8,429 
Current liabilities:
 
 
Accounts payable
699 
652 
Accrued and other current liabilities
175 
187 
Liabilities associated with assets held for sale, current
50 
3 
Customer margin deposits payable
14 
55 
Deferred income taxes, current
1 
0 
Derivative liabilities, current
72 
110 
Total current liabilities
1,011 
1,007 
Deferred income taxes
713 
788 
Long-term debt
2,047 
1,916 
Derivative liabilities, noncurrent
15 
12 
Asset retirement obligations
199 
310 
Other noncurrent liabilities
57 
186 
Contingent liabilities and commitments (Note 8)
   
   
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; 203.4 million shares issued at September 30, 2014 and 201 million shares issued at December 31, 2013)
2 
2 
Additional paid-in-capital
5,556 
5,516 
Accumulated deficit
(1,463)
(1,408)
Accumulated other comprehensive income (loss)
(1)
(1)
Total stockholders’ equity
4,094 
4,109 
Noncontrolling interests in consolidated subsidiaries
108 
101 
Total equity
4,202 
4,210 
Total liabilities and equity
$ 8,244 
$ 8,429 
Consolidated Balance Sheet (Unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 6 
$ 7 
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
203,400,000 
201,000,000 
Consolidated Statement of Operations (Unaudited) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Product revenues:
 
 
 
 
Natural gas sales
$ 207 
$ 210 
$ 798 
$ 699 
Oil and condensate sales
240 
183 
638 
473 
Natural gas liquid sales
54 
57 
170 
169 
Total product revenues
501 
450 
1,606 
1,341 
Gas management
145 
176 
937 
642 
Net gain (loss) on derivatives not designated as hedges (Note 10)
148 
(15)
(64)
(31)
Other
0 
5 
6 
16 
Total revenues
794 
616 
2,485 
1,968 
Costs and expenses:
 
 
 
 
Lease and facility operating
73 
70 
208 
196 
Gathering, processing and transportation
82 
88 
250 
264 
Taxes other than income
40 
33 
121 
95 
Gas management, including charges for unutilized pipeline capacity
164 
201 
788 
666 
Exploration (Note 4)
29 
21 
101 
59 
Depreciation, depletion and amortization
213 
230 
627 
662 
Impairment of costs of acquired unproved reserves
0 
19 
0 
19 
Loss on sale of working interests in the Piceance Basin
1 
0 
196 
0 
General and administrative
75 
67 
219 
209 
Other—net
3 
1 
9 
10 
Total costs and expenses
680 
730 
2,519 
2,180 
Operating income (loss)
114 
(114)
(34)
(212)
Interest expense
(31)
(28)
(88)
(82)
Interest capitalized
1 
1 
1 
1 
Investment income and other
5 
4 
12 
17 
Income (loss) from continuing operations before income taxes
89 
(137)
(109)
(276)
Provision (benefit) for income taxes
28 
(29)
(31)
(79)
Income (Loss) from continuing operations
61 
(108)
(78)
(197)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
5 
(8)
30 
(10)
Net income (loss)
66 
(116)
(48)
(207)
Less: Net income (loss) attributable to noncontrolling interests
4 
(2)
7 
5 
Net income (loss) attributable to WPX Energy, Inc.
$ 62 
$ (114)
$ (55)
$ (212)
Basic and diluted earnings (loss) per common share:
 
 
 
 
Income (loss) from continuing operations
$ 0.28 
$ (0.53)
$ (0.42)
$ (1.01)
Income (loss) from discontinued operations
$ 0.02 
$ (0.04)
$ 0.15 
$ (0.05)
Net income (loss)
$ 0.30 
$ (0.57)
$ (0.27)
$ (1.06)
Weighted Average Number of Shares Outstanding, Basic
203.3 
200.7 
202.5 
200.3 
Weighted Average Number of Shares Outstanding, Diluted
207.5 1
200.7 1
202.5 
200.3 1
[1] For the nine months ended September 30, 2014, 2.8 million weighted-average nonvested restricted stock units and awards and 1.0 million 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. for the nine months ended September 30, 2014. For the three and nine months ended September 30, 2013, 2.7 million and 2.3 million, respectively, weighted-average nonvested restricted stock units and awards and 1.2 million and 1.1 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. for the three and nine months ended September 30, 2013.
Consolidated Statement of Comprehensive Income (Loss) (Unaudited) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net income (loss) attributable to WPX Energy, Inc.
$ 62 
$ (114)
$ (55)
$ (212)
Other comprehensive income (loss):
 
 
 
 
Net reclassifications into earnings of net cash flow hedge realized gains, net of tax (a)
0 
0 
0 
(3)1
Other comprehensive income (loss), net of tax
0 
0 
0 
(3)
Comprehensive income (loss) attributable to WPX Energy, Inc.
$ 62 
$ (114)
$ (55)
$ (215)
Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
 
Reclassification adjustment on derivatives included in net income, tax
$ 2 
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion) (a)
$ 5 
Consolidated Statement of Changes in Equity (Unaudited) (USD $)
In Millions, unless otherwise specified
Total
Common Stock
Additional Paid-In- Capital
Accumulated Deficit
Accumulated Other Comprehensive Income (Loss)
Total Stockholders’ Equity
Noncontrolling Interests in Consolidated Subsidiaries
December 31, 2013 at Dec. 31, 2013
$ 4,210 
$ 2 
$ 5,516 
$ (1,408)
$ (1)
$ 4,109 
$ 101 1
Comprehensive income (loss):
 
 
 
 
 
 
 
Net income (loss)
(48)
 
 
(55)
 
(55)
7 1
Other comprehensive loss
0 
 
 
 
0 
0 
 
Comprehensive income (loss)
(48)
 
 
 
 
 
 
Stock based compensation
40 
 
40 
 
 
40 
 
Contributions from Noncontrolling Interests
0 
 
 
 
 
 
0 
September 30, 2014 at Sep. 30, 2014
$ 4,202 
$ 2 
$ 5,556 
$ (1,463)
$ (1)
$ 4,094 
$ 108 1
Consolidated Statement of Changes in Equity (Parenthetical)
Sep. 30, 2014
Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
 
 
Noncontrolling interest, ownership percentage by noncontrolling owners
31.00% 
31.00% 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Operating Activities
 
 
Net income (loss)
$ (48)
$ (207)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation Depletion And Amortization Including Discontinued Portion
638 
699 
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations
(55)
(67)
Provision for impairment of properties and equipment (including certain exploration expenses)
95 
64 
Amortization of stock-based awards
26 
24 
Gain (Loss) on Disposition of Assets
195 
(5)
Cash provided (used) by operating assets and liabilities:
 
 
Accounts receivable
71 
55 
Inventories
1 
(5)
Margin deposits and customer margin deposit payable
(22)
(2)
Other current assets
16 
(11)
Accounts payable
(15)
(5)
Accrued and other current liabilities
(22)
(32)
Changes in current and noncurrent derivative assets and liabilities
(106)
18 
Other, including changes in other noncurrent assets and liabilities
5 
(6)
Net cash provided by operating activities
779 
520 
Investing Activities
 
 
Capital expenditures
(1,325)1
(843)1
Proceeds from sale of assets
389 2
10 2
Other
(3)
(3)
Net cash used in investing activities
(939)
(836)
Financing Activities
 
 
Proceeds from common stock
15 
4 
Proceeds from long-term debt
500 
0 
Borrowings on credit facility
1,451 
605 
Payments on credit facility
(1,816)
(335)
Payments of Debt Issuance Costs
(6)
 
Payments for debt issuance costs
 
0 
Other
(12)
(1)
Net cash provided by financing activities
132 
273 
Net increase (decrease) in cash and cash equivalents
(28)
(43)
Effect of Exchange Rate on Cash and Cash Equivalents
(6)
(2)
Cash and cash equivalents at beginning of period
99 
153 
Cash and cash equivalents at end of period
65 
108 
Increase to properties and equipment
(1,389)
(864)
Changes in related accounts payable and accounts receivable
$ 64 
$ 21 
Basis of Presentation and Description of Business
Basis of Presentation and Description of Business
Basis of Presentation and Description of Business
Basis of Presentation
The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2013 in the Company’s Annual Report on Form 10-K. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2014, results of operations for the three and nine months ended September 30, 2014 and 2013, changes in equity for the nine months ended September 30, 2014 and cash flows for the nine months ended September 30, 2014 and 2013.
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.
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. As a result, we have reported the results of operations of the Powder River Basin as discontinued operations (see Note 2).
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
Description of Business
Operations of our company are located in the United States and South America and are organized into domestic and international reportable segments.
Domestic includes natural gas, oil and natural gas liquids (“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 and coalbed methane reserves 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.
International primarily consists of our ownership 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. See Note 12 for a discussion of a recently announced agreement to sell our international interests.
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”.
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 have 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.
Discontinued Operations Discontinued Operations (Notes)
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]
Discontinued Operations
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. The transaction is expected to close in the fourth quarter of 2014. The mid-year proved reserves in the basin were 222 Bcfe and third quarter production was 146 MMcf per day, which includes operated and non-operated working interests in approximately 5,000 wells. The Company has not actively drilled in the basin since 2011.
Summarized Results of Discontinued Operations
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Revenues
$
41

 
$
42

 
$
151

 
$
136

Costs and expenses:
 
 
 
 
 
 
 
Lease and facility operating
11

 
12

 
32

 
34

Gathering, processing and transportation
16

 
18

 
51

 
60

Taxes other than income
4

 
3

 
12

 
12

Exploration
—

 
—

 
—

 
1

Depreciation, depletion and amortization
3

 
11

 
11

 
37

General and administrative
1

 
1

 
3

 
5

Other—net
—

 
9

 
—

 
8

Total costs and expenses
35

 
54

 
109

 
157

Operating income (loss)
6

 
(12
)
 
42

 
(21
)
Interest capitalized
—

 
1

 
1

 
3

Investment income and other
1

 
—

 
4

 
3

Income (loss) from discontinued operations before income taxes
7

 
(11
)
 
47

 
(15
)
Provision (benefit) for income taxes
2

 
(3
)
 
17

 
(5
)
Income (loss) from discontinued operations
$
5

 
$
(8
)
 
$
30

 
$
(10
)


Assets and Liabilities in the Consolidated Balance Sheet Attributable to Discontinued Operations
 
September 30,
2014
 
December 31, 2013 (a)
 
(Millions)
Assets
 
 
 
Current assets:
 
 
 
Inventories
$
1

 
$
1

Total current assets
1

 
1

Investments
18

 
16

Properties and equipment (successful efforts method of accounting)
176

 
167

Less—accumulated depreciation, depletion and amortization
(11
)
 
—

Properties and equipment, net
165

 
167

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

 
$
184

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities:
 
 
 
Accrued and other current liabilities
$
3

 
$
3

Total current liabilities
3

 
3

Asset retirement obligations
47

 
48

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

 
$
51

__________
(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.

Cash Flows Attributable to Discontinued Operations
Excluding taxes and changes to working capital related to Powder River, total cash provided by operating activities related to discontinued operations was $58 million and $23 million for the nine months ended September 30, 2014 and 2013, respectively. Total cash used in investing activities related to discontinued operations was $7 million and $3 million for the nine months ended September 30, 2014 and 2013, respectively.
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share
The following table summarizes the calculation of earnings per share.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(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
$
57

 
$
(106
)
 
$
(85
)
 
$
(202
)
Basic weighted-average shares
203.3

 
200.7

 
202.5

 
200.3

Effect of dilutive securities (a):
 
 
 
 
 
 
 
Nonvested restricted stock units and awards
3.2

 
—

 
—

 
—

Stock options
1.0

 
—

 
—

 
—

Diluted weighted-average shares
207.5

 
200.7

 
202.5

 
200.3

Earnings (loss) per common share:
 
 
 
 
 
 
 
Basic
$
0.28

 
$
(0.53
)
 
$
(0.42
)
 
$
(1.01
)
Diluted
$
0.28

 
$
(0.53
)
 
$
(0.42
)
 
$
(1.01
)

__________
(a) For the nine months ended September 30, 2014, 2.8 million weighted-average nonvested restricted stock units and awards and 1.0 million 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. for the nine months ended September 30, 2014. For the three and nine months ended September 30, 2013, 2.7 million and 2.3 million, respectively, weighted-average nonvested restricted stock units and awards and 1.2 million and 1.1 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. for the three and nine months ended September 30, 2013.
The table below includes information related to stock options that were outstanding as of September 30, 2013 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.
 
September 30,
 
2014
 
2013
Options excluded (millions)
—

 
0.4

Weighted-average exercise price of options excluded
$
—

 
$
20.23

Exercise price range of options excluded
—

 
$19.95 - $20.97

Third quarter weighted-average market price
$
23.67

 
$
19.23

Asset Sale, Impairments and Exploration Expense
Asset Sales Impairments Exploration Expenses And Other Accruals [Text Block]
Asset Sale, Impairments and Exploration Expenses
Asset Sale
In May 2014, we agreed to the sale of portions of our working interests in certain Piceance Basin wells to Legacy Reserves LP (“Legacy”) for $355 million cash, subject to closing adjustments and based on 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 represent approximately 300 billion cubic feet of proved reserves, or approximately 6 percent of WPX’s year-end 2013 proved reserves. Production related to these working interests for January through May approximated 70 MMcfe/day of our production. The sale closed at the beginning of June and we received proceeds of $337 million which were subject to post closing adjustments including settlement of production for April and May. We estimate the amount to be remitted to Legacy in the fourth quarter will be $12 million. 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.
Impairment of Cost of Acquired Unproved Reserves
As a result of declines in forward natural gas prices during the third quarter of 2013 as compared to prior periods, we performed impairment assessments of our capitalized cost of acquired unproved reserves. Accordingly, we recorded a $19 million impairment of capitalized costs of acquired unproved reserves in the Kokopelli area of the Piceance Basin during the third quarter of 2013.
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Geologic and geophysical costs
$
1

 
$
6

 
$
8

 
$
14

Dry hole costs and impairments of exploratory area well costs
7

 
—

 
25

 
2

Unproved leasehold property impairment, amortization and expiration
21

 
15

 
68

 
43

Total exploration expenses
$
29

 
$
21

 
$
101

 
$
59


Dry hole costs and impairments of exploratory area well costs for the three and nine months ended September 30, 2014 includes $6 million and $16 million, respectively, of impairments of well costs in exploratory areas in the United States where management has determined to cease exploratory activities. The remaining amount represents impairment of international well costs and dry hole costs associated with exploratory wells in the United States where hydrocarbons were not detected. As of September 30, 2014, our total domestic capitalized well costs associated with our exploratory areas, including the Niobrara Shale in the Piceance Basin, totaled approximately $70 million.
Included in unproved leasehold property impairment, amortization and expiration for the three and nine months ended September 30, 2014, are impairments totaling $15 million and $41 million, respectively, for unproved leasehold costs in exploratory areas where the company no longer intends to continue exploration activities.
Inventories
Inventories
Inventories and Properties and Equipment
Inventories
 
September 30,
2014
 
December 31,
2013
 
(Millions)
Natural gas in underground storage
$
14

 
$
13

Crude oil production in transit
3

 
10

Material, supplies and other
53

 
48

 
$
70

 
$
71


Properties and Equipment
During the third quarter of 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 price is subject to post closing adjustments and therefore, the allocation is preliminary. The purchase is included within our capital expenditures on the Consolidated Statement of Cash Flows. 
Also during the third quarter of 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.
Asset Retirement Obligation
A rollforward of our asset retirement obligations for the current year is presented below.
 
Nine months ended September 30, 2014
 
(Millions)
Balance, January 1, 2014
$
313

Liabilities incurred
17

Liabilities settled
(1
)
Liabilities associated with assets sold
(65
)
Estimate revisions (a)
(78
)
Accretion expense
16

Balance, September 30, 2014
202

Amount reflected as current
$
3

__________
(a)
Estimate revisions are primarily associated with decreases in anticipated future plug and abandonment costs.
Debt and Banking Arrangements
Debt and Banking Arrangements
Debt and Banking Arrangements
As of the indicated dates, our debt consisted of the following:
 
September 30,
2014
 
December 31,
2013
 
(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
45

 
410

Apco
6

 
8

Other
1

 
1

     Total debt
$
2,052

 
$
1,919

Less: Current portion of long-term debt
5

 
3

     Total long-term debt
$
2,047

 
$
1,916


Senior Notes
In September 2014, we issued $500 million in face value 5.25% Senior Notes due 2024 (the "Notes”) pursuant to our automatic shelf registration statement on Form S-3 filed with the Securities and Exchange Commission. The 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 "Indenture"). The net proceeds from the offering of the 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 and for related transaction fees and expenses.
Optional Redemption. We have the option, at any time or from time to time prior to June 15, 2024 (which is three months prior to the maturity date of the 2024 notes) to redeem some or all of the Notes at a specified "make whole" premium as described in the Indenture. We also have the option at any time or from time to time on or after June 15, 2024, to redeem some or all of the Notes at a redemption price equal to 100% of the principal amount of the Notes to be redeemed.
Change of Control. If we experience a change of control (as defined in the indenture governing the Notes) accompanied by a specified rating decline, we must offer to repurchase the Notes at 101% of their principal amount, plus accrued and unpaid interest.
Covenants. The terms of the Indenture 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 Indenture also requires us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the Indenture. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The Indenture does 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 Indenture with respect to the Notes:
(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
At September 30, 2014 we had a $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”) that was set to expire in 2016. Under the terms of the Credit Facility Agreement and subject to certain requirements, we could 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. As of September 30, 2014, the variable interest rate was 4.13 percent on the $45 million outstanding under the Credit Facility Agreement.
Subsequent to September 30, 2014, we amended and restated the Credit Facility Agreement, hereafter referred to as the "New Credit Facility Agreement". The terms of the New Credit Facility Agreement are materially the same as our Credit Facility Agreement, except that the New Credit Facility Agreement matures on October 28, 2019, the letters of credit sublimit is $750 million and we changed the Applicable Rates and revised our financial covenants as set forth below. As of November 4, 2014, we had $210 million outstanding under the New Credit Facility Agreement and approximately $1.3 billion of available capacity.
Under the New Credit Facility Agreement, when our Index Debt is not rated BBB- or better by S&P or Baa3 or better by Moody’s and not less than BB+ or Ba1 by the other such agency, we will be required to maintain a ratio of Consolidated Net Indebtedness (as defined in the New Credit Facility Agreement) to Consolidated EBITDAX (as defined in the New 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 (as defined in the New Credit Facility Agreement) 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.  During a Downgrade Period (as defined in the New Credit Facility Agreement), we will 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 New 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 thereafter. This covenant will not apply after the occurrence of the Investment Grade Date, which is the first date after closing on which our Index Debt ratings are 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.
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 New Credit Facility Agreement. At September 30, 2014, a total of $324 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: 
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Current:
 
 
 
 
 
 
 
Federal
$
(5
)
 
$
(31
)
 
$
12

 
$
(28
)
State
(3
)
 
—

 
1

 
—

Foreign
4

 
3

 
8

 
11

 
(4
)
 
(28
)
 
21

 
(17
)
Deferred:
 
 
 
 
 
 
 
Federal
29

 
(27
)
 
(59
)
 
(84
)
State
3

 
12

 
6

 
8

Foreign
—

 
14

 
1

 
14

 
32

 
(1
)
 
(52
)
 
(62
)
Total provision (benefit)
$
28

 
$
(29
)
 
$
(31
)
 
$
(79
)

The effective tax rate for all periods presented above differs from the federal statutory rate primarily due to the effects of state income taxes and taxes on foreign operations.
Tax reform legislation was enacted by the state of New York on March 31, 2014, and has 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.
As of September 30, 2014, the amount of unrecognized tax benefits is not material. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with domestic or international matters will result in a significant increase or decrease of our unrecognized tax benefit.
In September 2013, the Argentine government enacted tax reform legislation related to dividends and capital gains which will apply to the Argentine operations of our consolidated investment in Apco, a Cayman Islands corporation. As a result, Apco recorded approximately $14 million of foreign deferred tax expense during third quarter 2013. This accrual was partially offset by approximately $4 million of U.S. deferred tax benefit recorded by WPX.
Pursuant to our tax sharing agreement with The Williams Companies, Inc. (“Williams”), 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 issues 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 unrelated to our business.
Contingent Liabilities
Contingent Liabilities
Contingent Liabilities
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 process under that standard of conducting an accounting, and the parties have jointly submitted the information to the court for approval. However, we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law.
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 October 2007 through September 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.
Matter 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 September 30, 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 September 30, 2014 and December 31, 2013, the Company had accrued approximately $20 million and $16 million, respectively, 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.
Fair Value Measurements
Fair Value Measurements
Fair Value Measurements
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.
 
September 30, 2014
 
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$
18

 
$
110

 
$
1

 
$
129

 
$
30

 
$
26

 
$
1

 
$
57

Energy derivative liabilities
$
61

 
$
26

 
$
—

 
$
87

 
$
83

 
$
38

 
$
1

 
$
122

Total debt (a)
$
—

 
$
2,081

 
$
—

 
$
2,081

 
$
—

 
$
1,945

 
$
—

 
$
1,945

__________
(a)
The carrying value of total debt, excluding capital leases, was $2,051 million and $1,918 million as of September 30, 2014 and December 31, 2013, respectively.
Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“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, option and swaption 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 at the end of 2015. 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 or market indications 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 were a net asset of $1 million at September 30, 2014, and 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 occurred during the periods ended September 30, 2014 and 2013.
There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
 
 
 
 
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.
The following table sets forth the derivative notional volumes that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of September 30, 2014.
  Derivatives related to production
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Henry Hub
 
(315
)
 
$
4.19

Natural Gas
 
Oct-Dec 2014
 
Swaptions
 
Henry Hub
 
(50
)
 
$
4.24

Natural Gas
 
Oct-Dec 2014
 
Costless Collars
 
Henry Hub
 
(190
)
 
$ 4.04 - 4.66

Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
Dominion
 
(39
)
 
$
(0.73
)
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
NGPL
 
(30
)
 
$
(0.19
)
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
Rockies
 
(143
)
 
$
(0.15
)
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
San Juan
 
(255
)
 
$
(0.15
)
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
SoCal
 
(73
)
 
$
0.13

Natural Gas
 
2015
 
Fixed Price Swaps
 
Henry Hub
 
(272
)
 
$
4.31

Natural Gas
 
2015
 
Swaptions
 
Henry Hub
 
(50
)
 
$
4.38

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
 
Swaptions
 
Henry Hub
 
(90
)
 
$
4.23

Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
Oct-Dec 2014
 
Fixed Price Swaps
 
WTI
 
(14,975
)
 
$
96.01

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

Crude Oil
 
2015
 
Swaptions
 
WTI
 
(8,382
)
 
$
94.90

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

NGL
 
 
 
 
 
 
 
 
 
 
NGL Ethane
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(3,261
)
 
$
0.29

NGL Propane
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(489
)
 
$
1.17

NGL Iso Butane
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(652
)
 
$
1.37

NGL Normal Butane
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(652
)
 
$
1.34

NGL Natural Gasoline
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(1,630
)
 
$
2.06

__________
(a)
Derivatives related to crude oil production are business day average swaps, basis swaps and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. The derivatives related to natural gas liquids are fixed price swaps. 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, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
(c)
The weighted average price for natural gas is reported in $/MMBtu, the crude oil price is reported in $/Bbl and natural gas liquids are reported in $/Gallon. All natural gas basis swaps are based on a differential to Henry Hub.

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 September 30, 2014.
Derivatives primarily related to storage and transportation
Commodity
 
Period
 
Contract Type (a)
 
Location (b)
 
Notional Volume (c)
 
Weighted Average
Price (d)
Natural Gas
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Multiple
 
8

 
—
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
Multiple
 
(31
)
 
—
Natural Gas
 
Oct-Dec 2014
 
Index
 
Multiple
 
(145
)
 
—
Natural Gas
 
2015
 
Fixed Price Swaps
 
Multiple
 
(11
)
 
—
Natural Gas
 
2015
 
Basis Swaps
 
Multiple
 
(12
)
 
—
Natural Gas
 
2015
 
Index
 
Multiple
 
(118
)
 
—
Natural Gas
 
2016
 
Index
 
Multiple
 
(70
)
 
—
Natural Gas
 
  2017+
 
Index
 
Multiple
 
(478
)
 
—
__________
(a)
WPX Marketing enters 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)
WPX Marketing transacts 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.
(d)
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.
 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.
 
September 30, 2014
 
December 31, 2013
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production not designated as hedging instruments
$
110

 
$
26

 
$
26

 
$
39

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

 
61

 
31

 
83

Total derivatives not designated as hedging instruments
$
129

 
$
87

 
$
57

 
$
122


 
During the first nine months of 2013, we reclassified $5 million of net gain on derivatives designated as cash flow hedges from accumulated other comprehensive income (loss) into income. These gains primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas 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.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Gain (loss) from derivatives related to production not designated as hedging instruments (a)
$
150

 
$
(18
)
 
$
40

 
$
(29
)
Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)
(2
)
 
3

 
(104
)
 
(2
)
Net gain (loss) on derivatives not designated as hedges
$
148

 
$
(15
)
 
$
(64
)
 
$
(31
)

__________
(a)
Includes receipts totaling $10 million and $1 million for settlements of derivatives during the three months ended September 30, 2014 and 2013, respectively; and payments totaling $57 million and $14 million for the nine months ended September 30, 2014 and 2013, respectively.
(b)
Includes receipts totaling $5 million for settlements of derivatives during the three months ended September 30, 2014 and payments totaling $2 million during the three months ended September 30, 2013; and payments totaling $114 million for the nine months ended September 30, 2014 and receipts of $1 million for the nine months ended September 30, 2013.
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
September 30, 2014
(Millions)
Derivative assets with right of offset or master netting agreements
$
129

 
$
(43
)
 
$
—

 
$
86

Derivative liabilities with right of offset or master netting agreements
$
(87
)
 
$
43

 
$
43

 
$
(1
)
 
 
 
 
 
 
 
 
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 Standard and Poor’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 September 30, 2014, we had collateral totaling $51 million posted to derivative counterparties, which included $8 million of initial margin to clearinghouses or exchanges to enter into positions and $43 million of maintenance margin for changes in the fair value of those positions, to support the aggregate fair value of our net $44 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. 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 $1 million at September 30, 2014. 
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.

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 and 2013, 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 September 30, 2014, is summarized as follows:
Counterparty Type
Gross Investment
Grade  (a)
 
Gross Total
 
Net Investment
Grade  (a)
 
Net Total
 
(Millions)
Financial institutions
$
128

 
$
128

 
$
85

 
$
85

Utilities
—

 
1

 
—

 
1

 
$
128

 
129

 
$
85

 
86

Credit reserves
 
 
—

 
 
 
—

Credit exposure from derivatives
 
 
$
129

 
 
 
$
86

 
__________
(a)
We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.
 
Our nine largest net counterparty positions represent approximately 94 percent of our gross 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
The customer margin deposits payable as of September 30, 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.
Segment Disclosures
Segment Disclosures
Segment Disclosures
Our reporting segments are domestic and international (see Note 1).
Our segment presentation is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions. Domestic and international maintain separate capital and cash management structures. These factors, coupled with differences in the business environment associated with operating in different countries, serve to differentiate the management of this entity as a whole.
Performance Measurement
We evaluate performance based upon segment revenues and segment operating income (loss). There are no intersegment sales between domestic and international.
The following tables reflect the reconciliation of segment revenues and segment operating income (loss) to revenues and operating income (loss) as reported in the Consolidated Statements of Operations.
 
 
 
 
 
 
 
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Three months ended September 30, 2014
 
 
 
 
 
Total revenues
$
747

 
$
47

 
$
794

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
63

 
$
10

 
$
73

Gathering, processing and transportation
82

 
—

 
82

Taxes other than income
32

 
8

 
40

Gas management, including charges for unutilized pipeline capacity
164

 
—

 
164

Exploration (Note 4)
28

 
1

 
29

Depreciation, depletion and amortization
201

 
12

 
213

Loss on sale of working interests in the Piceance Basin
1

 
—

 
1

General and administrative
71

 
4

 
75

Other—net
3

 
—

 
3

Total costs and expenses
$
645

 
$
35

 
$
680

Operating income (loss)
$
102

 
$
12

 
$
114

Interest expense
(31
)
 
—

 
(31
)
Interest capitalized
1

 
—

 
1

Investment income and other
(1
)
 
6

 
5

Income (loss) from continuing operations before income taxes
$
71

 
$
18

 
$
89

 
 
 
 
 
 
Three months ended September 30, 2013
 
 
 
 
 
Total revenues
$
581

 
$
35

 
$
616

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
62

 
$
8

 
$
70

Gathering, processing and transportation
88

 
—

 
88

Taxes other than income
27

 
6

 
33

Gas management, including charges for unutilized pipeline capacity
201

 
—

 
201

Exploration (Note 4)
21

 
—

 
21

Depreciation, depletion and amortization
222

 
8

 
230

Impairment of costs of acquired unproved reserves (Note 4)
19

 
—

 
19

General and administrative
64

 
3

 
67

Other—net
(2
)
 
3

 
1

Total costs and expenses
$
702

 
$
28

 
$
730

Operating income (loss)
$
(121
)
 
$
7

 
$
(114
)
Interest expense
(28
)
 
—

 
(28
)
Interest capitalized
1

 
—

 
1

Investment income and other
—

 
4

 
4

Income (loss) from continuing operations before income taxes
$
(148
)
 
$
11

 
$
(137
)
 
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Nine months ended September 30, 2014
 
 
 
 
 
Total revenues
$
2,368

 
$
117

 
$
2,485

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
182

 
$
26

 
$
208

Gathering, processing and transportation
249

 
1

 
250

Taxes other than income
100

 
21

 
121

Gas management, including charges for unutilized pipeline capacity
788

 
—

 
788

Exploration (Note 4)
97

 
4

 
101

Depreciation, depletion and amortization
596

 
31

 
627

Loss on sale of working interests in the Piceance Basin
196

 
—

 
196

General and administrative
208

 
11

 
219

Other—net
6

 
3

 
9

Total costs and expenses
$
2,422

 
$
97

 
$
2,519

Operating income (loss)
$
(54
)
 
$
20

 
$
(34
)
Interest expense
(88
)
 
—

 
(88
)
Interest capitalized
1

 
—

 
1

Investment income and other
(1
)
 
13

 
12

Income (loss) from continuing operations before income taxes
$
(142
)
 
$
33

 
$
(109
)
 
 
 
 
 
 
Nine months ended September 30, 2013
 
 
 
 
 
Total revenues
$
1,855

 
$
113

 
$
1,968

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
170

 
$
26

 
$
196

Gathering, processing and transportation
262

 
2

 
264

Taxes other than income
77

 
18

 
95

Gas management, including charges for unutilized pipeline capacity
666

 
—

 
666

Exploration (Note 4)
55

 
4

 
59

Depreciation, depletion and amortization
637

 
25

 
662

Impairment of costs of acquired unproved reserves (Note 4)
19

 
—

 
19

General and administrative
198

 
11

 
209

Other—net
10

 
—

 
10

Total costs and expenses
$
2,094

 
$
86

 
$
2,180

Operating income (loss)
$
(239
)
 
$
27

 
$
(212
)
Interest expense
(82
)
 
—

 
(82
)
Interest capitalized
1

 
—

 
1

Investment income and other
1

 
16

 
17

Income (loss) from continuing operations before income taxes
$
(319
)
 
$
43

 
$
(276
)
 
 
 
 
 
 
Total assets
 
 
 
 
 
Total assets as of September 30, 2014
$
7,838

 
$
406

 
$
8,244

Total assets as of December 31, 2013
$
8,046

 
$
383

 
$
8,429

Subsequent Events (Notes)
Subsequent Events [Text Block]
Subsequent Events
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 Oil and Gas International ("APCO"). Our international interests include a 69 percent controlling equity interest in APCO, additional non-material assets in wholly-owned Northwest Argentina and a 5 percent interest in Apco Argentina. Our international interests did not qualify as assets held for sale as of September 30, 2014. Therefore, the results of operations and financial position of our international segment will be reported in discontinued operations in future filings.
Discontinued Operations Discontinued Operation (Tables)
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block] 
Summarized Results of Discontinued Operations
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Revenues
$
41

 
$
42

 
$
151

 
$
136

Costs and expenses:
 
 
 
 
 
 
 
Lease and facility operating
11

 
12

 
32

 
34

Gathering, processing and transportation
16

 
18

 
51

 
60

Taxes other than income
4

 
3

 
12

 
12

Exploration
—

 
—

 
—

 
1

Depreciation, depletion and amortization
3

 
11

 
11

 
37

General and administrative
1

 
1

 
3

 
5

Other—net
—

 
9

 
—

 
8

Total costs and expenses
35

 
54

 
109

 
157

Operating income (loss)
6

 
(12
)
 
42

 
(21
)
Interest capitalized
—

 
1

 
1

 
3

Investment income and other
1

 
—

 
4

 
3

Income (loss) from discontinued operations before income taxes
7

 
(11
)
 
47

 
(15
)
Provision (benefit) for income taxes
2

 
(3
)
 
17

 
(5
)
Income (loss) from discontinued operations
$
5

 
$
(8
)
 
$
30

 
$
(10
)
Balance Sheet Disclosures by Disposal Groups, Including Discontinued Operations [Table Text Block] 
Assets and Liabilities in the Consolidated Balance Sheet Attributable to Discontinued Operations
 
September 30,
2014
 
December 31, 2013 (a)
 
(Millions)
Assets
 
 
 
Current assets:
 
 
 
Inventories
$
1

 
$
1

Total current assets
1

 
1

Investments
18

 
16

Properties and equipment (successful efforts method of accounting)
176

 
167

Less—accumulated depreciation, depletion and amortization
(11
)
 
—

Properties and equipment, net
165

 
167

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

 
$
184

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities:
 
 
 
Accrued and other current liabilities
$
3

 
$
3

Total current liabilities
3

 
3

Asset retirement obligations
47

 
48

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

 
$
51

__________
(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.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(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
$
57

 
$
(106
)
 
$
(85
)
 
$
(202
)
Basic weighted-average shares
203.3

 
200.7

 
202.5

 
200.3

Effect of dilutive securities (a):
 
 
 
 
 
 
 
Nonvested restricted stock units and awards
3.2

 
—

 
—

 
—

Stock options
1.0

 
—

 
—

 
—

Diluted weighted-average shares
207.5

 
200.7

 
202.5

 
200.3

Earnings (loss) per common share:
 
 
 
 
 
 
 
Basic
$
0.28

 
$
(0.53
)
 
$
(0.42
)
 
$
(1.01
)
Diluted
$
0.28

 
$
(0.53
)
 
$
(0.42
)
 
$
(1.01
)

__________
(a) For the nine months ended September 30, 2014, 2.8 million weighted-average nonvested restricted stock units and awards and 1.0 million 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. for the nine months ended September 30, 2014. For the three and nine months ended September 30, 2013, 2.7 million and 2.3 million, respectively, weighted-average nonvested restricted stock units and awards and 1.2 million and 1.1 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. for the three and nine months ended September 30, 2013.
Schedule of Stock Options Outstanding Excluded from Computation of weighted-average stock 
The table below includes information related to stock options that were outstanding as of September 30, 2013 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.
 
September 30,
 
2014
 
2013
Options excluded (millions)
—

 
0.4

Weighted-average exercise price of options excluded
$
—

 
$
20.23

Exercise price range of options excluded
—

 
$19.95 - $20.97

Third quarter weighted-average market price
$
23.67

 
$
19.23

Exploration Expense (Tables)
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Geologic and geophysical costs
$
1

 
$
6

 
$
8

 
$
14

Dry hole costs and impairments of exploratory area well costs
7

 
—

 
25

 
2

Unproved leasehold property impairment, amortization and expiration
21

 
15

 
68

 
43

Total exploration expenses
$
29

 
$
21

 
$
101

 
$
59

Inventories (Tables)
Inventories 
 
September 30,
2014
 
December 31,
2013
 
(Millions)
Natural gas in underground storage
$
14

 
$
13

Crude oil production in transit
3

 
10

Material, supplies and other
53

 
48

 
$
70

 
$
71

Schedule of Asset Retirement Obligations [Table Text Block] 
A rollforward of our asset retirement obligations for the current year is presented below.
 
Nine months ended September 30, 2014
 
(Millions)
Balance, January 1, 2014
$
313

Liabilities incurred
17

Liabilities settled
(1
)
Liabilities associated with assets sold
(65
)
Estimate revisions (a)
(78
)
Accretion expense
16

Balance, September 30, 2014
202

Amount reflected as current
$
3

__________
(a)
Estimate revisions are primarily associated with decreases in anticipated future plug and abandonment costs.
Debt and Banking Arrangements (Tables)
Schedule of Long-term Debt Instruments
As of the indicated dates, our debt consisted of the following:
 
September 30,
2014
 
December 31,
2013
 
(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
45

 
410

Apco
6

 
8

Other
1

 
1

     Total debt
$
2,052

 
$
1,919

Less: Current portion of long-term debt
5

 
3

     Total long-term debt
$
2,047

 
$
1,916

Provision (Benefit) for Income Taxes (Tables)
Provision (Benefit) for Income Taxes from Continuing Operations
The provision (benefit) for income taxes from continuing operations includes: 
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Current:
 
 
 
 
 
 
 
Federal
$
(5
)
 
$
(31
)
 
$
12

 
$
(28
)
State
(3
)
 
—

 
1

 
—

Foreign
4

 
3

 
8

 
11

 
(4
)
 
(28
)
 
21

 
(17
)
Deferred:
 
 
 
 
 
 
 
Federal
29

 
(27
)
 
(59
)
 
(84
)
State
3

 
12

 
6

 
8

Foreign
—

 
14

 
1

 
14

 
32

 
(1
)
 
(52
)
 
(62
)
Total provision (benefit)
$
28

 
$
(29
)
 
$
(31
)
 
$
(79
)
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.
 
September 30, 2014
 
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$
18

 
$
110

 
$
1

 
$
129

 
$
30

 
$
26

 
$
1

 
$
57

Energy derivative liabilities
$
61

 
$
26

 
$
—

 
$
87

 
$
83

 
$
38

 
$
1

 
$
122

Total debt (a)
$
—

 
$
2,081

 
$
—

 
$
2,081

 
$
—

 
$
1,945

 
$
—

 
$
1,945

__________
(a)
The carrying value of total debt, excluding capital leases, was $2,051 million and $1,918 million as of September 30, 2014 and December 31, 2013, respectively.
Derivatives and Concentration of Credit Risk (Tables)
Derivative Volume 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 
The following table sets forth the derivative notional volumes that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of September 30, 2014.
  Derivatives related to production
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Henry Hub
 
(315
)
 
$
4.19

Natural Gas
 
Oct-Dec 2014
 
Swaptions
 
Henry Hub
 
(50
)
 
$
4.24

Natural Gas
 
Oct-Dec 2014
 
Costless Collars
 
Henry Hub
 
(190
)
 
$ 4.04 - 4.66

Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
Dominion
 
(39
)
 
$
(0.73
)
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
NGPL
 
(30
)
 
$
(0.19
)
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
Rockies
 
(143
)
 
$
(0.15
)
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
San Juan
 
(255
)
 
$
(0.15
)
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
SoCal
 
(73
)
 
$
0.13

Natural Gas
 
2015
 
Fixed Price Swaps
 
Henry Hub
 
(272
)
 
$
4.31

Natural Gas
 
2015
 
Swaptions
 
Henry Hub
 
(50
)
 
$
4.38

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
 
Swaptions
 
Henry Hub
 
(90
)
 
$
4.23

Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
Oct-Dec 2014
 
Fixed Price Swaps
 
WTI
 
(14,975
)
 
$
96.01

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

Crude Oil
 
2015
 
Swaptions
 
WTI
 
(8,382
)
 
$
94.90

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

NGL
 
 
 
 
 
 
 
 
 
 
NGL Ethane
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(3,261
)
 
$
0.29

NGL Propane
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(489
)
 
$
1.17

NGL Iso Butane
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(652
)
 
$
1.37

NGL Normal Butane
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(652
)
 
$
1.34

NGL Natural Gasoline
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(1,630
)
 
$
2.06

__________
(a)
Derivatives related to crude oil production are business day average swaps, basis swaps and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. The derivatives related to natural gas liquids are fixed price swaps. 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, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
(c)
The weighted average price for natural gas is reported in $/MMBtu, the crude oil price is reported in $/Bbl and natural gas liquids are reported in $/Gallon. All natural gas basis swaps are based on a differential to Henry Hub.

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 September 30, 2014.
Derivatives primarily related to storage and transportation
Commodity
 
Period
 
Contract Type (a)
 
Location (b)
 
Notional Volume (c)
 
Weighted Average
Price (d)
Natural Gas
 
Oct-Dec 2014
 
Fixed Price Swaps
 
Multiple
 
8

 
—
Natural Gas
 
Oct-Dec 2014
 
Basis Swaps
 
Multiple
 
(31
)
 
—
Natural Gas
 
Oct-Dec 2014
 
Index
 
Multiple
 
(145
)
 
—
Natural Gas
 
2015
 
Fixed Price Swaps
 
Multiple
 
(11
)
 
—
Natural Gas
 
2015
 
Basis Swaps
 
Multiple
 
(12
)
 
—
Natural Gas
 
2015
 
Index
 
Multiple
 
(118
)
 
—
Natural Gas
 
2016
 
Index
 
Multiple
 
(70
)
 
—
Natural Gas
 
  2017+
 
Index
 
Multiple
 
(478
)
 
—
__________
(a)
WPX Marketing enters 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)
WPX Marketing transacts 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.
(d)
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.
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.
 
September 30, 2014
 
December 31, 2013
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production not designated as hedging instruments
$
110

 
$
26

 
$
26

 
$
39

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

 
61

 
31

 
83

Total derivatives not designated as hedging instruments
$
129

 
$
87

 
$
57

 
$
122

Derivative Gain (Loss) 
The following table presents the net gain (loss) related to our energy commodity derivatives.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(Millions)
Gain (loss) from derivatives related to production not designated as hedging instruments (a)
$
150

 
$
(18
)
 
$
40

 
$
(29
)
Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)
(2
)
 
3

 
(104
)
 
(2
)
Net gain (loss) on derivatives not designated as hedges
$
148

 
$
(15
)
 
$
(64
)
 
$
(31
)

__________
(a)
Includes receipts totaling $10 million and $1 million for settlements of derivatives during the three months ended September 30, 2014 and 2013, respectively; and payments totaling $57 million and $14 million for the nine months ended September 30, 2014 and 2013, respectively.
(b)
Includes receipts totaling $5 million for settlements of derivatives during the three months ended September 30, 2014 and payments totaling $2 million during the three months ended September 30, 2013; and payments totaling $114 million for the nine months ended September 30, 2014 and receipts of $1 million for the
Gross And Net 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
September 30, 2014
(Millions)
Derivative assets with right of offset or master netting agreements
$
129

 
$
(43
)
 
$
—

 
$
86

Derivative liabilities with right of offset or master netting agreements
$
(87
)
 
$
43

 
$
43

 
$
(1
)
 
 
 
 
 
 
 
 
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.
Gross and Net Credit Exposure from Derivative Contracts 
The gross and net credit exposure from our derivative contracts as of September 30, 2014, is summarized as follows:
Counterparty Type
Gross Investment
Grade  (a)
 
Gross Total
 
Net Investment
Grade  (a)
 
Net Total
 
(Millions)
Financial institutions
$
128

 
$
128

 
$
85

 
$
85

Utilities
—

 
1

 
—

 
1

 
$
128

 
129

 
$
85

 
86

Credit reserves
 
 
—

 
 
 
—

Credit exposure from derivatives
 
 
$
129

 
 
 
$
86

 
__________
(a)
We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.
Segment Disclosures (Tables)
Reconciliation of Segment Revenues and Segment Operating Income (Loss)
The following tables reflect the reconciliation of segment revenues and segment operating income (loss) to revenues and operating income (loss) as reported in the Consolidated Statements of Operations.
 
 
 
 
 
 
 
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Three months ended September 30, 2014
 
 
 
 
 
Total revenues
$
747

 
$
47

 
$
794

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
63

 
$
10

 
$
73

Gathering, processing and transportation
82

 
—

 
82

Taxes other than income
32

 
8

 
40

Gas management, including charges for unutilized pipeline capacity
164

 
—

 
164

Exploration (Note 4)
28

 
1

 
29

Depreciation, depletion and amortization
201

 
12

 
213

Loss on sale of working interests in the Piceance Basin
1

 
—

 
1

General and administrative
71

 
4

 
75

Other—net
3

 
—

 
3

Total costs and expenses
$
645

 
$
35

 
$
680

Operating income (loss)
$
102

 
$
12

 
$
114

Interest expense
(31
)
 
—

 
(31
)
Interest capitalized
1

 
—

 
1

Investment income and other
(1
)
 
6

 
5

Income (loss) from continuing operations before income taxes
$
71

 
$
18

 
$
89

 
 
 
 
 
 
Three months ended September 30, 2013
 
 
 
 
 
Total revenues
$
581

 
$
35

 
$
616

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
62

 
$
8

 
$
70

Gathering, processing and transportation
88

 
—

 
88

Taxes other than income
27

 
6

 
33

Gas management, including charges for unutilized pipeline capacity
201

 
—

 
201

Exploration (Note 4)
21

 
—

 
21

Depreciation, depletion and amortization
222

 
8

 
230

Impairment of costs of acquired unproved reserves (Note 4)
19

 
—

 
19

General and administrative
64

 
3

 
67

Other—net
(2
)
 
3

 
1

Total costs and expenses
$
702

 
$
28

 
$
730

Operating income (loss)
$
(121
)
 
$
7

 
$
(114
)
Interest expense
(28
)
 
—

 
(28
)
Interest capitalized
1

 
—

 
1

Investment income and other
—

 
4

 
4

Income (loss) from continuing operations before income taxes
$
(148
)
 
$
11

 
$
(137
)
 
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Nine months ended September 30, 2014
 
 
 
 
 
Total revenues
$
2,368

 
$
117

 
$
2,485

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
182

 
$
26

 
$
208

Gathering, processing and transportation
249

 
1

 
250

Taxes other than income
100

 
21

 
121

Gas management, including charges for unutilized pipeline capacity
788

 
—

 
788

Exploration (Note 4)
97

 
4

 
101

Depreciation, depletion and amortization
596

 
31

 
627

Loss on sale of working interests in the Piceance Basin
196

 
—

 
196

General and administrative
208

 
11

 
219

Other—net
6

 
3

 
9

Total costs and expenses
$
2,422

 
$
97

 
$
2,519

Operating income (loss)
$
(54
)
 
$
20

 
$
(34
)
Interest expense
(88
)
 
—

 
(88
)
Interest capitalized
1

 
—

 
1

Investment income and other
(1
)
 
13

 
12

Income (loss) from continuing operations before income taxes
$
(142
)
 
$
33

 
$
(109
)
 
 
 
 
 
 
Nine months ended September 30, 2013
 
 
 
 
 
Total revenues
$
1,855

 
$
113

 
$
1,968

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
170

 
$
26

 
$
196

Gathering, processing and transportation
262

 
2

 
264

Taxes other than income
77

 
18

 
95

Gas management, including charges for unutilized pipeline capacity
666

 
—

 
666

Exploration (Note 4)
55

 
4

 
59

Depreciation, depletion and amortization
637

 
25

 
662

Impairment of costs of acquired unproved reserves (Note 4)
19

 
—

 
19

General and administrative
198

 
11

 
209

Other—net
10

 
—

 
10

Total costs and expenses
$
2,094

 
$
86

 
$
2,180

Operating income (loss)
$
(239
)
 
$
27

 
$
(212
)
Interest expense
(82
)
 
—

 
(82
)
Interest capitalized
1

 
—

 
1

Investment income and other
1

 
16

 
17

Income (loss) from continuing operations before income taxes
$
(319
)
 
$
43

 
$
(276
)
 
 
 
 
 
 
Total assets
 
 
 
 
 
Total assets as of September 30, 2014
$
7,838

 
$
406

 
$
8,244

Total assets as of December 31, 2013
$
8,046

 
$
383

 
$
8,429

Discontinued Operations Discontinued Operation (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
 
 
 
 
 
Disposal Group, Including Discontinued Operation, Revenue
$ 41 
$ 42 
$ 151 
$ 136 
 
Disposal Group, Including Discontinued Operation, Lease Operating Expense
11 
12 
32 
34 
 
Disposal Group Including Discontinued Operation Gathering and Transportation Expense
16 
18 
51 
60 
 
Disposal Group, Including Discontinued Operation Taxes other than income
4 
3 
12 
12 
 
Disposal Group Including Discontinued Operation Exploration Expense
0 
0 
0 
1 
 
Disposal Group, Including Discontinued Operation, Depreciation and Amortization
3 
11 
11 
37 
 
Disposal Group, Including Discontinued Operation, General and Administrative Expense
1 
1 
3 
5 
 
Disposal Group, Including Discontinued Operation, Other Expense
0 
9 
0 
8 
 
Disposal Group, Including Discontinued Operation, Operating Expense
35 
54 
109 
157 
 
Disposal Group, Including Discontinued Operation, Operating Income (Loss)
6 
(12)
42 
(21)
 
Disposal Group including Discontinued Operation Interest Costs Capitalized
0 
1 
1 
3 
 
Disposal Group Including Discontinued Operation Investment Income
1 
0 
4 
3 
 
Disposal Group Including Discontinued Operation Income before Tax
7 
(11)
47 
(15)
 
Discontinued Operation, Tax Effect of Discontinued Operation
2 
(3)
17 
(5)
 
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
5 
(8)
30 
(10)
 
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
 
 
 
 
 
Disposal Group, Including Discontinued Operation, Inventory
1 
 
1 
 
1 
Assets of Disposal Group, Including Discontinued Operation, Current
1 
 
1 
 
1 
Disposal Group, Including Discontinued Operation, Investment
18 
 
18 
 
16 1
Disposal Group Including Discontinued Operations Properties and Equipment (successful effort method)
176 
 
176 
 
167 1
Disposal Group Including Discontinued Operations Accumulated Depreciation Depletion and Amortization
(11)
 
(11)
 
0 1
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net
165 
 
165 
 
167 1
Assets of Disposal Group, Including Discontinued Operation, Noncurrent
184 
 
184 
 
184 1
Disposal Group, Including Discontinued Operation, Other Current Liabilities
3 
 
3 
 
3 
Liabilities of Disposal Group, Including Discontinued Operation, Current
3 
 
3 
 
3 
Disposal Group, Including Discontinued Operations Asset Retirement Obligations, Noncurrent
47 
 
47 
 
48 1
Liabilities of Disposal Group, Including Discontinued Operation, Noncurrent
50 1
 
50 1
 
51 1
Additional Disclosures [Abstract]
 
 
 
 
 
Daily Production
146 
 
 
 
 
Productive Oil Wells, Number of Wells, Gross
5,000 
 
5,000 
 
 
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities
 
 
58 
23 
 
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities
 
 
7 
3 
 
Powder River Basin [Member]
 
 
 
 
 
Additional Disclosures [Abstract]
 
 
 
 
 
Acquistion costs or sale proceeds
$ 155 
 
$ 155 
 
 
Proved Reserves Related to Sale of Assets
222 
 
222 
 
 
Earnings (Loss) Per Common Share from Continuing Operations (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
Income (Loss) from Continuing Operations Attributable to Parent
$ 57 
$ (106)
$ (85)
$ (202)
Weighted Average Number of Shares Outstanding, Basic
203.3 
200.7 
202.5 
200.3 
Weighted Average Number of Shares Outstanding, Diluted
207.5 1
200.7 1
202.5 
200.3 1
Basic (in dollars per share)
$ 0.28 
$ (0.53)
$ (0.42)
$ (1.01)
Diluted (in dollars per share)
$ 0.28 
$ (0.53)
$ (0.42)
$ (1.01)
Non Vested Restricted Stock Units [Member]
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
 
2.7 
2.8 
2.3 
Employee Stock Option [Member]
 
 
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
 
1.2 
1.0 
1.1 
Non Vested Restricted Stock Units [Member]
 
 
 
 
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
3.2 
0 
0 
0 
Employee Stock Option [Member]
 
 
 
 
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
1.0 
0 
0 
0 
[1] For the nine months ended September 30, 2014, 2.8 million weighted-average nonvested restricted stock units and awards and 1.0 million 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. for the nine months ended September 30, 2014. For the three and nine months ended September 30, 2013, 2.7 million and 2.3 million, respectively, weighted-average nonvested restricted stock units and awards and 1.2 million and 1.1 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. for the three and nine months ended September 30, 2013.
Earnings (Loss) Per Common Share from Continuing Operations (Details 1) (USD $)
In Millions, except Per Share data, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Earnings Per Share [Abstract]
 
 
Options excluded (millions)
0 
0.4 
Weighted-average exercise price of options excluded
$ 0.00 
$ 20.23 
Exercise price range of options excluded, lower limit
$ 0 
$ 19.95 
Exercise price range of options excluded, upper limit
$ 0 
$ 20.97 
Third quarter weighted-average market price
$ 23.67 
$ 19.23 
Exploration Expense (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
 
 
 
 
Geologic and geophysical costs
$ 1 
$ 6 
$ 8 
$ 14 
Dry hole costs and impairments of exploratory area well costs
7 
0 
25 
2 
Unproved leasehold property impairment, amortization and expiration
21 
15 
68 
43 
Total exploration expenses
$ 29 
$ 21 
$ 101 
$ 59 
Asset Sale, Impairments and Exploration Expense Exploration Expense Additional Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 5 Months Ended 6 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
May 31, 2014
Jun. 30, 2014
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2014
Subsequent Event [Member]
Sep. 30, 2014
Post Closing [Member]
Sep. 30, 2014
Working Interests [Member]
Sep. 30, 2014
Exploratory Area [Member]
Sep. 30, 2014
Exploratory Area [Member]
Sep. 30, 2014
Legacy [Member]
Piceance Basin [Member]
MMcf
Sep. 30, 2014
Piceance Basin [Member]
Legacy [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
Final Settlement Adjustment
 
 
 
 
 
 
$ 12 
 
 
 
 
 
 
Proved Reserves Related to Sale of Assets
 
 
 
 
 
 
 
 
 
 
 
300,000 
 
Percentage Ownership Of Incentive Distribution Rights
10.00% 
 
 
 
10.00% 
 
 
 
 
 
 
 
 
Production Related To The Sale Of Working Interests
 
 
70,000 
 
 
 
 
 
 
 
 
 
 
Percentage of proved reserves attributed to sale of producing assets
 
 
 
 
6.00% 
 
 
 
 
 
 
 
 
Proceeds from sale of assets
 
 
 
 
389 1
10 1
 
329 
337 
 
 
 
355 
Exploration Abandonment and Impairment Expense
6 
 
 
 
16 
 
 
 
 
 
 
 
 
Loss on sale of working interests in the Piceance Basin
1 
0 
 
195 
196 
0 
 
 
 
 
 
 
 
Costs Incurred Exploration Costs Not Expensed
 
 
 
 
70 
 
 
 
 
 
 
 
 
Unproved leasehold property impairment, amortization and expiration
$ 21 
$ 15 
 
 
$ 68 
$ 43 
 
 
 
$ 15 
$ 41 
 
 
Asset Sale, Impairments and Exploration Expense Additional Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Impaired Long-Lived Assets Held and Used [Line Items]
 
 
 
 
Impairment of costs of acquired unproved reserves
$ 0 
$ 19 
$ 0 
$ 19 
Piceance Basin [Member]
 
 
 
 
Impaired Long-Lived Assets Held and Used [Line Items]
 
 
 
 
Impairment of costs of acquired unproved reserves
 
$ 19 
 
 
Inventories (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Inventory Disclosure [Abstract]
 
 
Natural gas in underground storage
$ 14 
$ 13 
Crude oil production in transit
3 
10 
Material, supplies and other
53 
48 
Inventory, Total
$ 70 
$ 71 
Inventories and Properties and Equipment Asset Retirement Obligation Rollforward (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
Beginning Balance
$ 313 
Liabilities incurred
17 
Liabilities settled
(1)
Liabilities associated with assets sold
(65)
Estimate revisions
(78)1
Accretion expense
16 
Ending Balance
202 
Asset Retirement Obligation, Current
$ 3 
Inventories and Properties and Equipment Properties and Equipment (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Well
Sep. 30, 2014
Sep. 30, 2013
Property, Plant and Equipment [Line Items]
 
 
 
Payments to Acquire Oil and Gas Property
$ 150 
 
 
Proceeds from sale of assets
 
389 1
10 1
Percentage of working interest sold
49.00% 
49.00% 
 
Proved developed wells related to sale
100 
 
 
Funding commitment associated with joint development agreement
170 
 
 
Future wells associated with joint development agreement
400 
 
 
Proved Developed Reserves [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Payments to Acquire Oil and Gas Property
50 
 
 
TRDC LLC [Member] |
Piceance Basin [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Proceeds from sale of assets
 
$ 50 
 
Debt and Banking Arrangements (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
$ 2,052 
$ 1,919 
Debt, Current
5 
3 
Long-term debt
2,047 
1,916 
Senior Notes |
5.250% Senior Notes due 2017
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
400 
400 
Senior Notes |
6.000% Senior Notes due 2022
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
1,100 
1,100 
Senior Notes |
5.250% Senior Notes due 2024
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
500 
0 
Credit facility agreement
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
45 
410 
Other
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
1 
1 
Apco |
Credit facility agreement
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
$ 6 
$ 8 
Debt and Banking Arrangements (Parenthetical) (Details) (Senior Notes [Member])
Sep. 30, 2014
Dec. 31, 2013
Senior Notes Due Twenty Seventeen [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Stated Percentage
5.25% 
5.25% 
Senior Notes Due Twenty Twenty Two [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Stated Percentage
6.00% 
6.00% 
Senior Notes Due Twenty Twenty Four [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Stated Percentage
5.25% 
5.25% 
Debt and Banking Arrangements Narrative (Details) (USD $)
9 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
Contract
Dec. 31, 2013
Nov. 4, 2014
Subsequent Event
Sep. 30, 2014
MaturityYear2016 [Member]
Five-year senior unsecured revolving credit facility agreement
Sep. 30, 2014
MaturityYear2016 [Member]
Unsecured Revolving Credit Facility [Member]
Sep. 30, 2014
Senior Notes [Member]
Sep. 30, 2014
Line of Credit [Member]
Dec. 31, 2013
Line of Credit [Member]
Nov. 4, 2014
Line of Credit [Member]
Subsequent Event
Sep. 30, 2014
Change Of Control [Member]
Sep. 30, 2014
Prior to December 31, 2015 [Member]
Sep. 30, 2014
After December 31, 2015 [Member]
Line of Credit Facility [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Face Amount
$ 500,000,000 
 
 
 
 
 
 
 
 
 
 
 
Limit On Consolidated Indebtedness to Consolidated EBITDAX
3.75 
 
 
 
 
 
 
 
 
 
 
 
Net Proceeds From Debt Offering
 
 
 
 
 
494,000,000 
 
 
 
 
 
 
Credit facility agreement
 
 
 
1,500,000,000 
 
 
 
 
 
 
 
 
Debt instrument maturity length
 
 
 
 
5 years 
 
 
 
 
 
 
 
Increase in the commitments
 
 
 
300,000,000 
 
 
 
 
 
 
 
 
Interest rate at end of period
 
 
 
4.13% 
 
 
 
 
 
 
 
 
Outstanding amount
 
 
 
45,000,000 
 
 
 
 
 
 
 
 
Letters Of Credit Sublimit
750,000,000 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from Lines of Credit
2,052,000,000 
1,919,000,000 
 
 
 
 
45,000,000 
410,000,000 
210,000,000 
 
 
 
Reduction Attributable to Cash Maximum
50,000,000 
 
 
 
 
 
 
 
 
 
 
 
Limit On Consolidated Indebtedness
 
 
 
 
 
 
 
 
 
 
1.25 
1.50 
Number of letter of credit agreements
3 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit issued
324,000,000 
 
 
 
 
 
 
 
 
 
 
 
Debt Redemption Price As Percentage Of Principal
100.00% 
 
 
 
 
 
 
 
 
 
 
 
Percentage Of Repurchase Of Notes On Principal Amount Of Notes
 
 
 
 
 
 
 
 
 
101.00% 
 
 
Line of Credit Facility, Capacity Available for Trade Purchases
 
 
$ 1,300,000,000 
 
 
 
 
 
 
 
 
 
Provision (Benefit) for Income Taxes from Continuing Operations (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Current:
 
 
 
 
Federal
$ (5)
$ (31)
$ 12 
$ (28)
State
(3)
0 
1 
0 
Foreign
4 
3 
8 
11 
Total current
(4)
(28)
21 
(17)
Deferred:
 
 
 
 
Federal
29 
(27)
(59)
(84)
State
3 
12 
6 
8 
Foreign
0 
14 
1 
14 
Deferred Income Tax Expense (Benefit)
32 
(1)
(52)
(62)
Total provision (benefit)
$ 28 
$ (29)
$ (31)
$ (79)
Provision (Benefit) for Income Taxes Additional Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2014
Income Tax Disclosure [Abstract]
 
 
Deferred Tax Expense Related To New York Tax Reform Legislation
 
$ 9 
DeferredForeignIncomeTaxExpenseBenefit-Argentina
14 
 
US Deferred Income Tax Expense Benefit related to foreign operation
$ 4 
 
Contingent Liabilities - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
1 Months Ended 84 Months Ended
Sep. 30, 2006
Claim
Sep. 30, 2014
Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
 
 
 
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
 
$ 20 
$ 16 
Fair Value Measurements (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
$ 129 
$ 57 
Derivative Liability, Fair Value, Gross Liability
87 
122 
Level 1 |
Energy Related Derivative
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
18 
30 
Derivative Liability, Fair Value, Gross Liability
61 
83 
Long-term debt
0 1
0 1
Level 2 |
Energy Related Derivative
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
110 
26 
Derivative Liability, Fair Value, Gross Liability
26 
38 
Long-term debt
2,081 1
1,945 1
Level 3 |
Energy Related Derivative
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
1 
1 
Derivative Liability, Fair Value, Gross Liability
0 
1 
Long-term debt
0 1
0 1
Total |
Energy Related Derivative
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
129 
57 
Derivative Liability, Fair Value, Gross Liability
87 
122 
Long-term debt
$ 2,081 1
$ 1,945 1
Fair Value Measurements - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Assets And Liabilities Classified In Level 3 [Line Items]
 
 
Long-term debt
$ 2,051 
$ 1,918 
Percentage of net fair value of derivatives portfolio expiring
100.00% 
 
Derivative Portfolio Expiration Period
2015 
 
Level 3
 
 
Assets And Liabilities Classified In Level 3 [Line Items]
 
 
Derivative, Fair Value, Net
$ 1 
 
Derivatives and Concentration of Credit Risk (Details) (Short Position)
9 Months Ended
Sep. 30, 2014
2016 [Member] |
Derivatives related to production |
Crude Oil |
Swaptions |
WTI
 
Derivative [Line Items]
 
Notional Volume
5,250 1
Underlying, Derivative
97.55 2
2016 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Thirteen [Member] |
Swaptions |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
90,000 1
Underlying, Derivative
4.23 2
2016 [Member] |
Derivatives related to storage and transportation |
Natural Gas Commodity Contract Nine [Member] |
Index |
Multiple
 
Derivative [Line Items]
 
Notional Volume
70,000 3
Underlying, Derivative
0.00 4
2017 and beyond [Member] |
Derivatives related to storage and transportation |
Natural Gas Commodity Contract Ten [Member] |
Index |
Multiple
 
Derivative [Line Items]
 
Notional Volume
478,000 3
Underlying, Derivative
0.00 4
2014 [Member] |
Derivatives related to production |
Crude Oil |
Fixed Price Swaps |
WTI
 
Derivative [Line Items]
 
Notional Volume
14,975 1
Underlying, Derivative
96.01 2
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Two |
Swaptions |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
50,000 1
Underlying, Derivative
4.24 2
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Three |
Costless Collar [Member] |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
190,000 1
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Three |
Costless Collar [Member] |
Henry Hub |
Minimum [Member]
 
Derivative [Line Items]
 
Underlying, Derivative
4.04 
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Three |
Costless Collar [Member] |
Henry Hub |
Maximum [Member]
 
Derivative [Line Items]
 
Underlying, Derivative
4.66 
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Four |
Basis Swap [Member] |
Dominion [Member]
 
Derivative [Line Items]
 
Notional Volume
39,000 1
Underlying, Derivative
(0.73)2
2014 [Member] |
Derivatives related to production |
Propane [Member] |
Fixed Price Swaps |
Mont Belvieu
 
Derivative [Line Items]
 
Notional Volume
489 1
Underlying, Derivative
1.17 2
2014 [Member] |
Derivatives related to production |
Isobutane [Member] |
Fixed Price Swaps |
Mont Belvieu
 
Derivative [Line Items]
 
Notional Volume
652 1
Underlying, Derivative
1.37 2
2014 [Member] |
Derivatives related to production |
Butane [Member] |
Fixed Price Swaps |
Mont Belvieu
 
Derivative [Line Items]
 
Notional Volume
652 1
Underlying, Derivative
1.34 2
2014 [Member] |
Derivatives related to production |
Natural Gasoline |
Fixed Price Swaps |
Mont Belvieu
 
Derivative [Line Items]
 
Notional Volume
1,630 1
Underlying, Derivative
2.06 2
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Five |
Basis Swap [Member] |
NGPL [Member]
 
Derivative [Line Items]
 
Notional Volume
30,000 1
Underlying, Derivative
(0.19)2
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Six |
Basis Swap [Member] |
Rockies
 
Derivative [Line Items]
 
Notional Volume
143,000 1
Underlying, Derivative
(0.15)2
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Seven [Member] |
Basis Swap [Member] |
San Juan [Member]
 
Derivative [Line Items]
 
Notional Volume
255,000 1
Underlying, Derivative
(0.15)2
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Seven [Member] |
Basis Swap [Member] |
Southern California [Member]
 
Derivative [Line Items]
 
Notional Volume
73,000 1
Underlying, Derivative
0.13 2
2014 [Member] |
Derivatives related to production |
Natural Gas Liquids Ethane [Member] |
Fixed Price Swaps |
Mont Belvieu
 
Derivative [Line Items]
 
Notional Volume
3,261 1
Underlying, Derivative
0.29 2
2014 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract One [Member] |
Fixed Price Swaps |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
315,000 1
Underlying, Derivative
4.19 2
2014 [Member] |
Derivatives related to storage and transportation |
Natural Gas Commodity Contract Two |
Fixed Price Swaps |
Multiple
 
Derivative [Line Items]
 
Notional Volume
8,000 3
Underlying, Derivative
0.00 4
2014 [Member] |
Derivatives related to storage and transportation |
Natural Gas Commodity Contract Two |
Basis Swap [Member] |
Multiple
 
Derivative [Line Items]
 
Notional Volume
31,000 3
Underlying, Derivative
0.00 4
2014 [Member] |
Derivatives related to storage and transportation |
Natural Gas Commodity Contract Three |
Index |
Multiple
 
Derivative [Line Items]
 
Notional Volume
145,000 3
Underlying, Derivative
0.00 4
2015 [Member] |
Derivatives related to production |
Crude Oil |
Swaptions |
WTI
 
Derivative [Line Items]
 
Notional Volume
8,382 1
Underlying, Derivative
94.90 2
2015 [Member] |
Derivatives related to production |
Crude Oil Commodity Contract One [Member] |
Fixed Price Swaps |
WTI
 
Derivative [Line Items]
 
Notional Volume
20,236 1
Underlying, Derivative
94.88 2
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Eight [Member] |
Fixed Price Swaps |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
272,000 1
Underlying, Derivative
4.31 2
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Ten [Member] |
Costless Collar [Member] |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
50,000 1
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Ten [Member] |
Costless Collar [Member] |
Henry Hub |
Minimum [Member]
 
Derivative [Line Items]
 
Underlying, Derivative
4.00 
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Ten [Member] |
Costless Collar [Member] |
Henry Hub |
Maximum [Member]
 
Derivative [Line Items]
 
Underlying, Derivative
4.50 
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Eleven [Member] |
Basis Swap [Member] |
NGPL [Member]
 
Derivative [Line Items]
 
Notional Volume
13,000 1
Underlying, Derivative
(0.16)2
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Twelve [Member] [Member] |
Basis Swap [Member] |
Rockies
 
Derivative [Line Items]
 
Notional Volume
150,000 1
Underlying, Derivative
(0.11)2
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Thirteen [Member] |
Basis Swap [Member] |
San Juan [Member]
 
Derivative [Line Items]
 
Notional Volume
85,000 1
Underlying, Derivative
(0.10)2
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Thirteen [Member] |
Basis Swap [Member] |
Southern California [Member]
 
Derivative [Line Items]
 
Notional Volume
20,000 1
Underlying, Derivative
0.18 2
2015 [Member] |
Derivatives related to production |
Natural Gas Commodity Contract Nine [Member] |
Swaptions |
Henry Hub
 
Derivative [Line Items]
 
Notional Volume
50,000 1
Underlying, Derivative
4.38 2
2015 [Member] |
Derivatives related to storage and transportation |
Natural Gas Commodity Contract Two |
Fixed Price Swaps |
Multiple
 
Derivative [Line Items]
 
Notional Volume
11,000 3
Underlying, Derivative
0.00 4
2015 [Member] |
Derivatives related to storage and transportation |
Natural Gas Commodity Contract Five |
Basis Swap [Member] |
Multiple
 
Derivative [Line Items]
 
Notional Volume
12,000 3
Underlying, Derivative
0.00 4
2015 [Member] |
Derivatives related to storage and transportation |
Natural Gas Commodity Contract Six |
Index |
Multiple
 
Derivative [Line Items]
 
Notional Volume
118,000 3
Underlying, Derivative
0.00 4
Derivatives and Concentration of Credit Risk (Details 1) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Not Designated as Hedging Instrument
Dec. 31, 2013
Not Designated as Hedging Instrument
Sep. 30, 2014
Legacy natural gas contracts from former power business
Not Designated as Hedging Instrument
Dec. 31, 2013
Legacy natural gas contracts from former power business
Not Designated as Hedging Instrument
Sep. 30, 2014
Derivatives related to production
Not Designated as Hedging Instrument
Dec. 31, 2013
Derivatives related to production
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
 
 
 
 
 
 
 
Document Period End Date
Sep. 30, 2014 
 
 
 
 
 
 
Total derivatives, Assets
 
$ 129 
$ 57 
$ 19 
$ 31 
$ 110 
$ 26 
Total derivatives, Liabilities
 
$ 87 
$ 122 
$ 61 
$ 83 
$ 26 
$ 39 
Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk (Details 2) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Net gain (loss) on derivatives not designated as hedges (Note 10)
$ 148 
$ (15)
$ (64)
$ (31)
Energy Related Derivative [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Payment Made for Settlement of Derivatives
 
 
57 
14 
Payment Received for Settlement of Derivatives
10 
1 
 
 
Net gain (loss) on derivatives not designated as hedges (Note 10)
150 1
(18)1
40 1
(29)1
Derivatives Related to Physical Marketing Agreements [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Payment Made for Settlement of Derivatives
 
2 
114 
 
Payment Received for Settlement of Derivatives
5 
 
 
1 
Net gain (loss) on derivatives not designated as hedges (Note 10)
$ (2)2
$ 3 2
$ (104)2
$ (2)2
Derivatives and Concentration of Credit Risk Derivatives and Concentration of Credit Risk (Details 3) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Gross And Net Derivative Assets and Liabilities [Line Items]
 
 
Document Period End Date
Sep. 30, 2014 
 
Derivative Asset, Fair Value, Gross Asset
$ 129 
$ 57 
Derivative Liability, Collateral, Right to Reclaim Cash, Offset
43 
52 
Derivative Liability, Fair Value, Gross Liability
(87)
(122)
Derivative, Collateral, Obligation to Return Cash
0 
0 
Derivative Assets
86 
7 
Derivative Liabilities
(1)
(20)
Counterparty Netting Under Agreements Governing Derivatives
 
 
Gross And Net Derivative Assets and Liabilities [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
43 1
50 1
Derivative Liability, Fair Value, Gross Liability
$ (43)1
$ (50)1
Derivatives and Concentration of Credit Risk (Details 4) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Credit Exposure From Derivatives [Line Items]
 
Total gross credit exposure from derivative contracts before credit reserve
$ 129 
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net
86 
Credit reserves
0 
Credit Reserves Maximum Potential Future Exposure On Credit Risk Derivatives Net
0 
Gross credit exposure from derivatives, Gross Total
129 
Maximum Potential Future Exposure On Credit Risk Derivatives Net
86 
Financial institutions
 
Credit Exposure From Derivatives [Line Items]
 
Total gross credit exposure from derivative contracts before credit reserve
128 
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net
85 
Utilities [Member]
 
Credit Exposure From Derivatives [Line Items]
 
Total gross credit exposure from derivative contracts before credit reserve
1 
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net
1 
Investment Grade
 
Credit Exposure From Derivatives [Line Items]
 
Total gross credit exposure from derivative contracts before credit reserve
128 1
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net
85 1
Investment Grade |
Financial institutions
 
Credit Exposure From Derivatives [Line Items]
 
Total gross credit exposure from derivative contracts before credit reserve
128 1
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net
85 1
Investment Grade |
Utilities [Member]
 
Credit Exposure From Derivatives [Line Items]
 
Total gross credit exposure from derivative contracts before credit reserve
0 1
Maximum Potential Future Exposure On Credit Risk Derivatives Before Credit Reserve Net
$ 0 1
Derivatives and Concentration of Credit Risk - Additional Information (Detail) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Derivative [Line Items]
 
 
Collateral Already Posted, Aggregate Fair Value
$ 51,000,000 
 
NumberOfLargestNetCounterPartyPositionsInvestmentGrade
9 
 
Occurrence Of Future Net Cash Flows For Derivatives
12 months 
 
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net
 
5,000,000 
Net derivative liability position
44,000,000 
 
Additional collateral posted
1,000,000 
 
Percentage of net credit exposure from derivatives
94.00% 
 
Gains or losses recognized in income from assessment of hedge
0 
 
Collateral Already Posted, Maintenance Margin, Aggregate Fair Value
43,000,000 
 
Collateral Already Posted, Initial Margin, Aggregate Fair Value
8,000,000 
 
Cash Flow Hedging [Member] |
Revenues [Member]
 
 
Derivative [Line Items]
 
 
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net
 
5,000,000 
Maximum [Member]
 
 
Derivative [Line Items]
 
 
Reduction in derivative liabilties
$ 1,000,000 
 
Segment Disclosures (Details) (USD $)
3 Months Ended 6 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Jun. 30, 2014
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Total revenues
$ 794,000,000 
$ 616,000,000 
 
$ 2,485,000,000 
$ 1,968,000,000 
 
Costs and expenses:
 
 
 
 
 
 
Lease and facility operating
73,000,000 
70,000,000 
 
208,000,000 
196,000,000 
 
Gathering, processing and transportation
82,000,000 
88,000,000 
 
250,000,000 
264,000,000 
 
Taxes other than income
40,000,000 
33,000,000 
 
121,000,000 
95,000,000 
 
Gas management, including charges for unutilized pipeline capacity
164,000,000 
201,000,000 
 
788,000,000 
666,000,000 
 
Exploration (Note 4)
29,000,000 
21,000,000 
 
101,000,000 
59,000,000 
 
Depreciation, depletion and amortization
213,000,000 
230,000,000 
 
627,000,000 
662,000,000 
 
Impairment of costs of acquired unproved reserves
0 
19,000,000 
 
0 
19,000,000 
 
Loss on sale of working interests in the Piceance Basin
1,000,000 
0 
195,000,000 
196,000,000 
0 
 
General and administrative
75,000,000 
67,000,000 
 
219,000,000 
209,000,000 
 
Other—net
3,000,000 
1,000,000 
 
9,000,000 
10,000,000 
 
Total costs and expenses
680,000,000 
730,000,000 
 
2,519,000,000 
2,180,000,000 
 
Operating income (loss)
114,000,000 
(114,000,000)
 
(34,000,000)
(212,000,000)
 
Interest expense
(31,000,000)
(28,000,000)
 
(88,000,000)
(82,000,000)
 
Interest capitalized
1,000,000 
1,000,000 
 
1,000,000 
1,000,000 
 
Investment income and other
5,000,000 
4,000,000 
 
12,000,000 
17,000,000 
 
Income (loss) from continuing operations before income taxes
89,000,000 
(137,000,000)
 
(109,000,000)
(276,000,000)
 
Total assets
 
 
 
 
 
 
Total assets
8,244,000,000 
 
 
8,244,000,000 
 
8,429,000,000 
Domestic
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Total revenues
747,000,000 
581,000,000 
 
2,368,000,000 
1,855,000,000 
 
Costs and expenses:
 
 
 
 
 
 
Lease and facility operating
63,000,000 
62,000,000 
 
182,000,000 
170,000,000 
 
Gathering, processing and transportation
82,000,000 
88,000,000 
 
249,000,000 
262,000,000 
 
Taxes other than income
32,000,000 
27,000,000 
 
100,000,000 
77,000,000 
 
Gas management, including charges for unutilized pipeline capacity
164,000,000 
201,000,000 
 
788,000,000 
666,000,000 
 
Exploration (Note 4)
28,000,000 
21,000,000 
 
97,000,000 
55,000,000 
 
Depreciation, depletion and amortization
201,000,000 
222,000,000 
 
596,000,000 
637,000,000 
 
Impairment of costs of acquired unproved reserves
 
19,000,000 
 
 
19,000,000 
 
Loss on sale of working interests in the Piceance Basin
1,000,000 
 
 
196,000,000 
 
 
General and administrative
71,000,000 
64,000,000 
 
208,000,000 
198,000,000 
 
Other—net
3,000,000 
(2,000,000)
 
6,000,000 
10,000,000 
 
Total costs and expenses
645,000,000 
702,000,000 
 
2,422,000,000 
2,094,000,000 
 
Operating income (loss)
102,000,000 
(121,000,000)
 
(54,000,000)
(239,000,000)
 
Interest expense
(31,000,000)
(28,000,000)
 
(88,000,000)
(82,000,000)
 
Interest capitalized
1,000,000 
1,000,000 
 
1,000,000 
1,000,000 
 
Investment income and other
(1,000,000)
0 
 
(1,000,000)
1,000,000 
 
Income (loss) from continuing operations before income taxes
71,000,000 
(148,000,000)
 
(142,000,000)
(319,000,000)
 
Total assets
 
 
 
 
 
 
Total assets
7,838,000,000 
 
 
7,838,000,000 
 
8,046,000,000 
International
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Total revenues
47,000,000 
35,000,000 
 
117,000,000 
113,000,000 
 
Costs and expenses:
 
 
 
 
 
 
Lease and facility operating
10,000,000 
8,000,000 
 
26,000,000 
26,000,000 
 
Gathering, processing and transportation
0 
0 
 
1,000,000 
2,000,000 
 
Taxes other than income
8,000,000 
6,000,000 
 
21,000,000 
18,000,000 
 
Gas management, including charges for unutilized pipeline capacity
0 
0 
 
0 
0 
 
Exploration (Note 4)
1,000,000 
0 
 
4,000,000 
4,000,000 
 
Depreciation, depletion and amortization
12,000,000 
8,000,000 
 
31,000,000 
25,000,000 
 
Impairment of costs of acquired unproved reserves
 
0 
 
 
0 
 
Loss on sale of working interests in the Piceance Basin
0 
 
 
0 
 
 
General and administrative
4,000,000 
3,000,000 
 
11,000,000 
11,000,000 
 
Other—net
0 
3,000,000 
 
3,000,000 
0 
 
Total costs and expenses
35,000,000 
28,000,000 
 
97,000,000 
86,000,000 
 
Operating income (loss)
12,000,000 
7,000,000 
 
20,000,000 
27,000,000 
 
Interest expense
0 
0 
 
0 
0 
 
Interest capitalized
0 
0 
 
0 
0 
 
Investment income and other
6,000,000 
4,000,000 
 
13,000,000 
16,000,000 
 
Income (loss) from continuing operations before income taxes
18,000,000 
11,000,000 
 
33,000,000 
43,000,000 
 
Total assets
 
 
 
 
 
 
Total assets
406,000,000 
 
 
406,000,000 
 
383,000,000 
Intersegment Eliminations [Member]
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Total revenues
$ 0 
 
 
 
 
 
Subsequent Events (Details) (Subsequent Event [Member], USD $)
In Millions, unless otherwise specified
Dec. 31, 2014
Subsequent Event [Line Items]
 
Equity Method Investment, Ownership Percentage
69.00% 
Noncontrolling Equity Interest Ownership Percentage
5.00% 
International
 
Subsequent Event [Line Items]
 
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds
$ 294