WPX ENERGY, INC., 10-Q filed on 8/6/2015
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2015
Aug. 5, 2015
Document Documentand Entity Information [Abstract]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Jun. 30, 2015 
 
Document Fiscal Year Focus
2015 
 
Document Fiscal Period Focus
Q2 
 
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
 
235,181,715 
Consolidated Balance Sheet (Unaudited) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2015
Dec. 31, 2014
Current assets:
 
 
Cash and cash equivalents
$ 317 
$ 41 
Accounts receivable, net of allowance of $7 million as of June 30, 2015 and $6 million as of December 31, 2014
280 
459 
Derivative assets, current
260 
498 
Inventories
48 
45 
Margin deposits
27 
Assets classified as held for sale, current
127 
773 
Other
28 
26 
Total current assets
1,067 
1,869 
Properties and equipment (successful efforts method of accounting)
12,158 
11,753 
Less—accumulated depreciation, depletion and amortization
(5,340)
(4,911)
Properties and equipment, net
6,818 
6,842 
Derivative assets, noncurrent
32 
38 
Other noncurrent assets
45 
49 
Total assets
7,962 
8,798 
Current liabilities:
 
 
Accounts payable
339 
712 
Accrued and other current liabilities
169 
177 
Liabilities of disposal group associated with assets held for sale
47 
132 
Deferred income taxes, current
149 
151 
Derivative liabilities, current
26 
37 
Total current liabilities
730 
1,209 
Deferred income taxes
611 
621 
Long-term debt
2,000 
2,280 
Derivative liabilities, noncurrent
Asset retirement obligations
208 
198 
Other noncurrent liabilities
41 
57 
Contingent liabilities and commitments (Note 8)
   
   
Stockholders’ equity:
 
 
Preferred stock (100 million shares authorized at $0.01 par value; no shares issued)
Common stock (2 billion shares authorized at $0.01 par value; 205.2 million shares issued at June 30, 2015 and 203.7 million shares issued at December 31, 2014)
Additional paid-in-capital
5,572 
5,562 
Accumulated deficit
(1,207)
(1,244)
Accumulated other comprehensive income (loss)
(1)
Total stockholders’ equity
4,367 
4,319 
Noncontrolling interests in consolidated subsidiaries
109 
Total equity
4,367 
4,428 
Total liabilities and equity
$ 7,962 
$ 8,798 
Consolidated Balance Sheet (Unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Jun. 30, 2015
Dec. 31, 2014
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 7 
$ 6 
Preferred stock, par value
$ 0.01 
$ 0.01 
Preferred stock, shares authorized
100,000,000 
100,000,000 
Preferred stock, shares issued
Common stock, par value
$ 0.01 
$ 0.01 
Common stock, shares authorized
2,000,000,000 
2,000,000,000 
Common stock, shares issued
205,200,000 
203,700,000 
Consolidated Statement of Operations (Unaudited) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2015
Jun. 30, 2014
Jun. 30, 2015
Jun. 30, 2014
Product revenues:
 
 
 
 
Natural gas sales
$ 127 
$ 262 
$ 294 
$ 579 
Oil and condensate sales
145 
194 
262 
343 
Natural gas liquid sales
25 
54 
48 
115 
Total product revenues
297 
510 
604 
1,037 
Gas management
57 
231 
215 
792 
Net gain (loss) on derivatives (Note 10)
(71)
(17)
34 
(212)
Other
Total revenues
284 
727 
856 
1,621 
Costs and expenses:
 
 
 
 
Lease and facility operating
51 
59 
108 
119 
Gathering, processing and transportation
69 
78 
142 
167 
Taxes other than income
19 
33 
41 
68 
Gas management, including charges for unutilized pipeline capacity
59 
233 
168 
624 
Exploration (Note 4)
54 
13 
69 
Depreciation, depletion and amortization
227 
202 
443 
395 
Net (gain) loss on sales of assets
(209)
(278)
Loss On Sale Of Working Interests
195 
195 
General and administrative
63 
70 
127 
137 
Other—net
31 
Total costs and expenses
290 
925 
795 
1,777 
Operating income (loss)
(6)
(198)
61 
(156)
Interest expense
(32)
(28)
(65)
(57)
Investment income and other
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest
(37)
(226)
 
 
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest
 
 
(2)
(213)
Provision (benefit) for income taxes
(14)
(82)
(1)
(69)
Income (Loss) from continuing operations
(23)
(144)
(1)
(144)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
(7)
11 
39 
30 
Net income (loss)
(30)
(133)
38 
(114)
Less: Net income (loss) attributable to noncontrolling interests
Comprehensive Income (Loss), Net of Tax, Attributable to Parent
(30)
(135)
37 
(117)
Income (Loss) from Continuing Operations Attributable to Parent
(23)
(144)
(1)
(144)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent
(7)
38 
27 
Comprehensive income (loss) attributable to WPX Energy, Inc.
$ (30)
$ (135)
$ 37 
$ (117)
Income (Loss) from Continuing Operations, Per Basic and Diluted Share
$ (0.12)
$ (0.71)
$ (0.01)
$ (0.71)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share
$ (0.02)
$ 0.05 
$ 0.19 
$ 0.13 
Earnings Per Share, Basic and Diluted
$ (0.14)
$ (0.66)
$ 0.18 
$ (0.58)
Weighted Average Number of Shares Outstanding, Basic and Diluted
205.0 
202.7 
204.6 
202.1 
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, 2014 at Dec. 31, 2014
$ 4,428 
$ 2 
$ 5,562 
$ (1,244)
$ (1)
$ 4,319 
$ 109 1
Decrease In Accumulated Other Comprehensive Income Due to Deconsolidation
 
 
 
 
 
Noncontrolling Interest, Decrease from Deconsolidation
 
 
 
 
 
 
(110)
Comprehensive income (loss):
 
 
 
 
 
 
 
Net income (loss)
38 
 
 
 
 
 
 
Comprehensive Income (Loss) Attributable to Parent
37 
 
 
37 
 
37 
 
Net Income (Loss) Attributable to Noncontrolling Interest
 
 
 
 
 
Comprehensive income (loss)
38 
 
 
 
 
 
 
Stock based compensation
10 
 
10 
 
 
10 
 
Decrease in Noncontrolling Interest and Accumulated Other Comprehensive Income Due To Deconsolidation
(109)
 
 
 
 
 
 
June 30, 2015 at Jun. 30, 2015
$ 4,367 
$ 2 
$ 5,572 
$ (1,207)
$ 0 
$ 4,367 
$ 0 1
Consolidated Statement of Changes in Equity (Parenthetical)
Jun. 30, 2015
Dec. 31, 2014
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
6 Months Ended
Jun. 30, 2015
Jun. 30, 2014
Operating Activities
 
 
Net income (loss)
$ 38 
$ (114)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation Depletion And Amortization Including Discontinued Portion
443 
422 
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations
(17)
(78)
Provision for impairment of properties and equipment (including certain exploration expenses)
26 
66 
Amortization of stock-based awards
20 
17 
Gain (Loss) on Disposition of Assets
(318)
195 
Cash provided (used) by operating assets and liabilities:
 
 
Accounts receivable
176 
34 
Inventories
(2)
(9)
Margin deposits and customer margin deposits payable
21 
(26)
Other current assets
(4)
15 
Accounts payable
(145)
Accrued and other current liabilities
(33)
(20)
Changes in current and noncurrent derivative assets and liabilities
233 
27 
Other, including changes in other noncurrent assets and liabilities
(8)
(10)
Net cash provided by operating activities
430 
520 
Investing Activities
 
 
Capital expenditures
(679)1
(728)1
Proceeds from sale of assets
772 
338 
Other
(5)
Net cash provided by (used in) investing activities
95 
(395)
Financing Activities
 
 
Proceeds from common stock
12 
Borrowings on credit facility
181 
904 
Payments on credit facility
(461)
(1,024)
Other
(6)
Net cash provided by (used in) financing activities
(278)
(114)
Net increase (decrease) in cash and cash equivalents
247 
11 
Effect of Exchange Rate on Cash and Cash Equivalents
(5)
Cash and Cash Equivalents, at Carrying Value, Including Discontinued Operations
70 2
99 2
Cash and cash equivalents at end of period
317 
105 
Increase to properties and equipment
(435)
(760)
Changes in related accounts payable and accounts receivable
$ (244)
$ 32 
Basis of Presentation and Description of Business
Basis of Presentation and Description of Business
Basis of Presentation and Description of Business
Description of Business
Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts, such as transportation and related derivatives, coupled with the sale of our commodity volumes.
In addition, we have operations in the Powder River Basin in Wyoming that are classified as held for sale and, until January 29, 2015, we had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”), an oil and gas exploration and production company with activities in Argentina and Colombia. For all periods presented, the results of Powder River Basin and Apco are reported as discontinued operations.
The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company,” is at times referred to in the first person as “we,” “us” or “our”.
Basis of Presentation
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, 2014 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 June 30, 2015, results of operations for the three and six months ended June 30, 2015 and 2014, changes in equity for the six months ended June 30, 2015 and cash flows for the six months ended June 30, 2015 and 2014.
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.
Our continuing operations are comprised of a single business segment, which includes the development, production and gas management activities of natural gas, oil and NGLs in the United States. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.
Discontinued Operations
On January 29, 2015, we completed the disposition of our international interests and received net proceeds of $291 million after expenses but before $17 million of cash on hand at Apco as of the closing date. The results of operations of our international segment have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheet as of December 31, 2014.
The results of operations of the Powder River Basin have also been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.
See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations. Additionally, see Note 8 for a discussion of contingencies related to Williams’ former power business (most of which was disposed of in 2007).
Recently Issued Accounting Standards     
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, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows.
In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Company does not expect the adoption of ASU 2014-15 to have a significant impact on its Consolidated Financial Statements or related disclosures.
In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The core principles of the guidance in ASU 2015-03 require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the guidance in this update. ASU 2015-03 is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. The Company does not believe the adoption of this guidance will have a material impact on its financial position, results of operations or cash flows. As of June 30, 2015, we have $26 million in debt issuance costs.
Discontinued Operations Discontinued Operations (Notes)
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]
Discontinued Operations
On October 3, 2014, we announced an agreement to sell our international interests for approximately $294 million subject to the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco. On January 29, 2015 we completed this divestiture and received net proceeds of $291 million after expenses but before $17 million of cash on hand at Apco as of the closing date. These non-operated international holdings comprised our international segment. We recorded a pretax gain of $41 million related to this transaction during first quarter 2015.
During the third quarter of 2014, our management signed an agreement to sell our remaining mature, coalbed methane holdings in the Powder River Basin for $155 million. This sales agreement did not successfully close in March 2015 and we subsequently terminated the transaction with the counterparty. Subsequent to June 30, 2015, we signed agreements for the sale of the Powder River Basin holdings (See Note 11). During the first half of 2015, we recorded a total of $16 million in impairments of the net assets to a probability weighted-average of expected sales prices. The Powder River operations have firm gathering and treating agreements with total commitments of $110 million through 2020. These commitments have been in excess of our production throughput. We also have certain pipeline capacity obligations held by our marketing company with total commitments for 2015 and thereafter totaling $155 million. Depending on the final terms upon closing a Powder River sale, we may record a portion of these obligations if they meet the definition of exit activities in association with exiting the Powder River Basin.
Summarized Results of Discontinued Operations
 
Three months ended June 30, 2015
 
Three months ended June 30, 2014
 
Powder River Basin
 
Powder River Basin
 
International
 
Total
 
(Millions)
Total revenues
$
17

 
$
48

 
$
39

 
$
87

Costs and expenses:
 
 
 
 
 
 
 
Lease and facility operating
$
7

 
$
10

 
$
8

 
$
18

Gathering, processing and transportation
14

 
18

 
1

 
19

Taxes other than income
1

 
2

 
7

 
9

Exploration

 

 
3

 
3

Depreciation, depletion and amortization

 
4

 
9

 
13

Impairment of assets held for sale
6

 

 

 

General and administrative

 
1

 
3

 
4

Other—net
1

 

 
2

 
2

Total costs and expenses
29

 
35

 
33

 
68

Operating income (loss)
(12
)
 
13

 
6

 
19

       Interest capitalized

 
1

 

 
1

Investment income and other
1

 

 
5

 
5

Income (loss) from discontinued operations before income taxes
(11
)
 
14

 
11

 
25

Provision (benefit) for income taxes
(4
)
 
7

 
7

 
14

Income (loss) from discontinued operations
$
(7
)
 
$
7

 
$
4

 
$
11


 
Six months ended June 30, 2015
 
Powder River Basin
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
42

 
$
15

 
$
57

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
17

 
$
4

 
$
21

Gathering, processing and transportation
28

 

 
28

Taxes other than income
4

 
3

 
7

Impairment of assets held for sale
16

 

 
16

General and administrative
1

 
1

 
2

Other—net

 

 

Total costs and expenses
66

 
8

 
74

Operating income (loss)
(24
)
 
7

 
(17
)
Investment income and other
3

 
1

 
4

Gain on sale of international assets

 
41

 
41

Income (loss) from discontinued operations before income taxes
(21
)
 
49

 
28

Provision (benefit) for income taxes (a)
(8
)
 
(3
)
 
(11
)
Income (loss) from discontinued operations
$
(13
)
 
$
52

 
$
39

__________
(a) International includes the reversal of certain U.S. deferred tax liabilities associated with Apco.

 
Six months ended June 30, 2014
 
Powder River Basin
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
110

 
$
70

 
$
180

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
21

 
$
16

 
$
37

Gathering, processing and transportation
35

 
1

 
36

Taxes other than income
8

 
13

 
21

Exploration

 
3

 
3

Depreciation, depletion and amortization
8

 
19

 
27

General and administrative
2

 
7

 
9

Other—net

 
3

 
3

Total costs and expenses
74

 
62

 
136

Operating income (loss)
36

 
8

 
44

       Interest capitalized
1

 

 
1

       Investment income and other
2

 
7

 
9

Income (loss) from discontinued operations before income taxes
39

 
15

 
54

Provision (benefit) for income taxes
15

 
9

 
24

Income (loss) from discontinued operations
$
24

 
$
6

 
$
30


Assets and Liabilities in the Consolidated Balance Sheet Attributable to Discontinued Operations

As of June 30, 2015, the following table presents assets classified as held for sale and liabilities associated with assets held for sale related to our Powder River Basin operations.
 
June 30, 2015
 
Total
 
(Millions)
Assets classified as held for sale
 
Current assets:
 
Inventories
$
1

Total current assets
1

Investments
18

Properties and equipment, net(a)
108

Total assets classified as held for sale on the Consolidated Balance Sheets
$
127

 
 
Liabilities associated with assets held for sale
 
Current liabilities:
 
Accrued and other current liabilities
$
3

Total current liabilities
3

Asset retirement obligations
44

Total liabilities associated with assets held for sale on the Consolidated Balance Sheets
$
47

__________
(a) Includes a cumulative total of $61 million in impairments of the net assets held for sale of the Powder River Basin.

As of December 31, 2014 the following table presents domestic assets classified as held for sale and liabilities associated with assets held for sale related to our Powder River Basin and Appalachian Basin operations, and the international assets classified as held for sale and liabilities associated with assets held for sale related to our international operations which were divested in January 2015.
 
December 31, 2014
 
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Assets classified as held for sale
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$

 
$
29

 
$
29

Accounts receivable

 
25

 
25

Inventories
1

 
7

 
8

Other

 
14

 
14

Total current assets
1

 
75

 
76

Investments
18

 
134

 
152

Properties and equipment, net(a)
122

 
217

 
339

Other noncurrent assets

 
6

 
6

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

 
$
432

 
$
573

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

 

 
200

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

 
$
432

 
$
773

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

 
$
34

 
$
34

Accrued and other current liabilities
3

 
23

 
26

Total current liabilities
3

 
57

 
60

Deferred income taxes

 
13

 
13

Long-term debt

 
2

 
2

Asset retirement obligations
45

 
7

 
52

Other noncurrent liabilities

 
3

 
3

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

 
$
82

 
$
130

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

 
$

 
$
2

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

 
$
82

 
$
132

__________
(a) Domestic includes a total of $45 million in impairments of the net assets held for sale of the Powder River Basin.

Cash Flows Attributable to Discontinued Operations
Excluding income taxes and changes to working capital, total cash used by operating activities related to the Powder River Basin was $6 million for the six months ended June 30, 2015 and total cash provided by operating activities was $48 million for the six months ended June 30, 2014. Total cash used in investing activities related to Powder River Basin discontinued operations was $3 million and $7 million for the six months ended June 30, 2015 and 2014, respectively. Cash provided by operating activities related to our international operations was $3 million and $19 million for the six months ended June 30, 2015 and 2014, respectively. Total cash used in investing activities related our international operations was $15 million and $36 million for the six months ended June 30, 2015 and 2014, respectively.
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
The following table summarizes the calculation of earnings per share.
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(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
$
(23
)
 
$
(144
)
 
$
(1
)
 
$
(144
)
Basic weighted-average shares
205.0

 
202.7

 
204.6

 
202.1

Diluted weighted-average shares(a)
205.0

 
202.7

 
204.6

 
202.1

Earnings (loss) per common share from continuing operations:
 
 
 
 
 
 
 
Basic
$
(0.12
)
 
$
(0.71
)
 
$
(0.01
)
 
$
(0.71
)
Diluted
$
(0.12
)
 
$
(0.71
)
 
$
(0.01
)
 
$
(0.71
)

__________
(a) The following table includes amounts that 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.
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Weighted-average nonvested restricted stock units and awards
1.7

 
2.4

 
1.7

 
2.5

Weighted-average stock options
0.1

 
1.1

 
0.1

 
1.0


The table below includes information related to stock options that were outstanding at June 30, 2015 and 2014 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the second quarter weighted-average market price of our common shares.
 
June 30,
 
2015
 
2014
Options excluded (millions)
2.0

 
0.1

Weighted-average exercise price of options excluded
$
17.42

 
$
21.45

Exercise price range of options excluded
$13.46 - $21.81

 
$21.45 - $21.45

Second quarter weighted-average market price
$
13.18

 
$
21.27



For the six months ended June 30, 2015, approximately 1.0 million nonvested restricted stock units were antidilutive and were excluded from the computation of diluted weighted-average shares.
Asset Sale, Impairments and Exploration Expense
Asset Sales Impairments Exploration Expenses And Other Accruals [Text Block]
Asset Sales, Other Expenses and Exploration Expenses
Asset Sales
During May 2015, WPX completed the sale of a package of marketing contracts and release of certain related firm transportation capacity in the Northeast for approximately $209 million in cash. The transaction released WPX from various long-term natural gas purchase and sales obligations and approximately $390 million in future demand payment obligations associated with the transport position. As a result of this transaction, we recorded a net gain of $209 million in second-quarter 2015 on these executory contracts.
During the first quarter of 2015, we sold a portion of our Appalachian Basin operations and released certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $288 million, subject to post closing adjustments. Including an estimate of post closing adjustments, we recorded a net gain of $69 million in first-quarter 2015. This transaction included physical operations covering approximately 46,700 acres, roughly 50 MMcfe per day of net natural gas production and 63 horizontal wells. The assets were primarily located in the Appalachian Basin in Susquehanna County, Pennsylvania. The transaction also included the release of firm transportation capacity that we had under contract in the Northeast, primarily 260 MMcfe per day with Millennium Pipeline. Upon the transfer of the firm capacity, we were released from approximately $24 million per year in annual demand obligations associated with the transport.
During the second quarter of 2014, we completed the sale of a portion of our working interests in certain Piceance Basin wells. Based on an estimated total value received at closing of $329 million which represented estimated final cash proceeds and an estimated fair value of incentive distribution rights we received, we recorded a $195 million loss on the sale for the three and six months ended June 30, 2014.
Other Expenses
During the first quarter of 2015, we executed a termination and settlement agreement to release us from a crude oil transportation and sales agreement in anticipation of entering into a different agreement with another third party with more favorable terms. As a result of this contract termination and settlement, we recorded an expense of approximately $22 million which is included in Other—net on the Consolidated Statements of Operations.
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Geologic and geophysical costs
$
1

 
$
3

 
$
2

 
$
7

Dry hole costs and impairments of exploratory area well costs

 
15

 

 
15

Unproved leasehold property impairment, amortization and expiration
5

 
36

 
11

 
47

Total exploration expenses
$
6

 
$
54

 
$
13

 
$
69


Dry hole costs and impairments of exploratory area well costs for the three and six months ended June 30, 2014 includes $10 million of impairments of well costs in an exploratory area in the United States where management had determined to cease exploratory activities. The remaining amount represents dry hole costs associated with exploratory wells in the United States where hydrocarbons were not detected.
Included in unproved leasehold property impairment, amortization and expiration for the three and six months ended June 30, 2014, are impairments totaling $26 million for unproved leasehold costs in two exploratory areas where the Company no longer intends to continue exploration activities.
As of June 30, 2015, our total capitalized well costs associated with our exploratory areas, including the Niobrara Shale in the Piceance Basin, totaled approximately $76 million.
Inventories
Inventories
Inventories
The following table presents a summary of our inventories as of the dates indicated below.
 
June 30,
2015
 
December 31,
2014
 
(Millions)
Material, supplies and other
$
48

 
$
43

Crude oil production in transit

 
2

     Total inventories
$
48

 
$
45

Debt and Banking Arrangements
Debt and Banking Arrangements
Debt and Banking Arrangements
The following table presents a summary of our debt as of the dates indicated below.
 
June 30,
2015
 
December 31,
2014
 
(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

 
500

Credit facility agreement

 
280

Other
1

 
1

     Total debt
$
2,001

 
$
2,281

Less: Current portion of long-term debt
1

 
1

     Total long-term debt
$
2,000

 
$
2,280


Senior Notes
See Note 11 for a discussion of $1 billion in senior notes which were issued subsequent to June 30, 2015 and our Annual Report on Form 10-K for the year ended December 31, 2014 for a discussion of our previously issued senior notes.
Credit Facility
We have a $1.5 billion five-year senior unsecured revolving credit facility agreement with Citibank, N.A., as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). Under the terms of the Credit Facility and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. The Credit Facility matures on October 28, 2019. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of June 30, 2015, we were in compliance with our financial covenants and had full access to the Credit Facility. For additional information regarding the terms of our Credit Facility prior to recent amendments, see our Annual Report on Form 10-K for the year ended December 31, 2014. See Note 11 for a discussion of recent amendments to our Credit Facility and increases in the commitments from existing banks subsequent to June 30, 2015.
Letters of Credit
WPX has also entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility. At June 30, 2015, a total of $233 million in letters of credit have been issued.
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
The following table presents the provision (benefit) for income taxes from continuing operations. 
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Current:
 
 
 
 
 
 
 
Federal
$

 
$
11

 
$

 
$
12

State

 
2

 

 
2

 

 
13

 

 
14

Deferred:
 
 
 
 
 
 
 
Federal
(13
)
 
(85
)
 
(1
)
 
(86
)
State
(1
)
 
(10
)
 

 
3

 
(14
)
 
(95
)
 
(1
)
 
(83
)
Total provision (benefit)
$
(14
)
 
$
(82
)
 
$
(1
)
 
$
(69
)

The effective tax rate for all periods presented above differs from the federal statutory rate primarily due to the effects of state income taxes.
As a result of the sale of Apco in the first quarter of 2015, we no longer have foreign operations and the associated tax liabilities. The closing of Apco resulted in a $42 million capital loss for which a valuation allowance was established in 2014.
Tax reform legislation was enacted by the state of New York on March 31, 2014, and had an impact on us as a result of our marketing activities in the state. As a result, we recorded an additional $9 million of deferred tax expense in the first quarter of 2014 to accrue for the impact of this new legislation.
As of June 30, 2015, 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 will result in a significant increase or decrease of our unrecognized tax benefit.
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. In addition, 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. 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. It is uncertain when the IRS will complete that audit.
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 accounting process under the standard and have obtained the court's approval. However, as we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law, we have appealed this matter to the Colorado Court of Appeals. Plaintiffs have now filed a second class action lawsuit in the District Court, Garfield County containing similar allegations but related to subsequent time periods. The parties have agreed to stay this new lawsuit pending resolution of the first lawsuit in the Colorado Court of Appeals.
In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico. In March 2015, the court denied plaintiffs' motion for class certification. Plaintiffs have not timely filed an appeal of this denial. They have filed both a pending motion for reconsideration of the denial of class certification with the trial court which we oppose and a motion seeking to conduct additional discovery in order to attempt to redefine their proposed class, which has been denied. 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 and 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 July 2008 through June 2015, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $115 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 a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us for 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 in the Western States Antitrust Litigation holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered in favor of the defendants. The U.S. Supreme Court granted Defendants' writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. 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 June 30, 2015, 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 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 June 30, 2015 and December 31, 2014, the Company had accrued approximately $16 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
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.
 
June 30, 2015
 
December 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$
9

 
$
282

 
$
1

 
$
292

 
$
14

 
$
517

 
$
5

 
$
536

Energy derivative liabilities
$
13

 
$
17

 
$
1

 
$
31

 
$
32

 
$
10

 
$

 
$
42

Total debt(a)
$

 
$
1,961

 
$

 
$
1,961

 
$

 
$
2,218

 
$

 
$
2,218

__________
(a)
The carrying value of total debt, excluding capital leases, was $2,000 million and $2,280 million as of June 30, 2015 and December 31, 2014, 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 2016. 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 liability of less than $1 million at June 30, 2015, 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 June 30, 2015 and 2014.
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.
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. 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 contracts economically hedge the expected cash flows generated by those agreements.
Derivatives related to 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 June 30, 2015.
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
Jul-Dec 2015
 
Fixed Price Swaps
 
Henry Hub
 
(410
)
 
$
4.05

Natural Gas
 
Jul-Dec 2015
 
Costless Collars
 
Henry Hub
 
(50
)
 
$ 4.00 - 4.50

Natural Gas
 
Jul-Dec 2015
 
Basis Swaps
 
NGPL
 
(20
)
 
$
(0.18
)
Natural Gas
 
Jul-Dec 2015
 
Basis Swaps
 
Rockies
 
(280
)
 
$
(0.17
)
Natural Gas
 
Jul-Dec 2015
 
Basis Swaps
 
San Juan
 
(108
)
 
$
(0.11
)
Natural Gas
 
Jul-Dec 2015
 
Basis Swaps
 
SoCal
 
(50
)
 
$
0.08

Natural Gas
 
2016
 
Fixed Price Swaps
 
Henry Hub
 
(280
)
 
$
3.81

Natural Gas
 
2016
 
Swaptions
 
Henry Hub
 
(90
)
 
$
4.23

Natural Gas
 
2017
 
Swaptions
 
Henry Hub
 
(65
)
 
$
4.19

Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
Jul -Dec 2015
 
Fixed Price Swaps
 
WTI
 
(18,500
)
 
$
94.75

Crude Oil
 
2016
 
Fixed Price Swaps
 
WTI
 
(15,500
)
 
$
61.86

Crude Oil
 
2016
 
Swaptions
 
WTI
 
(8,500
)
 
$
84.27

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

Derivatives primarily related to transportation
The following table sets forth the derivative notional volumes of the net long (short) positions of derivatives primarily related to transportation contracts, which are included in our commodity derivatives portfolio as of June 30, 2015. The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.
Commodity
 
Period
 
Contract Type (a)
 
Location (b)
 
Notional Volume (c)
Natural Gas
 
Jul-Dec 2015
 
Fixed Price Swaps
 
Multiple
 
(4
)
Natural Gas
 
Jul-Dec 2015
 
Basis Swaps
 
Multiple
 
(1
)
Natural Gas
 
Jul-Dec 2015
 
Index
 
Multiple
 
(51
)
__________
(a)
We enter into exchange traded fixed price and basis swaps, over-the-counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.
(b)
We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation and asset management agreements.
(c)
Natural gas volumes are reported in BBtu/day.

Fair values and gains (losses)
        
The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.
 
June 30, 2015
 
December 31, 2014
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production
$
282

 
$
17

 
$
517

 
$
10

Derivatives related to physical marketing agreements
10

 
14

 
19

 
32

Total derivatives
$
292

 
$
31

 
$
536

 
$
42


We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting on derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives.
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Gain (loss) from derivatives related to production (a)
$
(68
)
 
$
(24
)
 
$
54

 
$
(110
)
Gain (loss) from derivatives related to physical marketing agreements (b)
(3
)
 
7

 
(20
)
 
(102
)
Net gain (loss) on derivatives not designated as hedges
$
(71
)
 
$
(17
)
 
$
34

 
$
(212
)

(a)
Includes receipts totaling $137 million and payments totaling $16 million for settlements of derivatives during the three months ended June 30, 2015 and 2014, respectively; and receipts totaling $295 million and payments totaling $66 million for the six months ended June 30, 2015 and 2014, respectively.
(b)
Includes payments totaling $5 million and $1 million for settlements of derivatives during the three months ended June 30, 2015 and 2014, respectively; and payments totaling $28 million and $119 million for the six months ended June 30, 2015 and 2014, respectively.
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
June 30, 2015
(Millions)
Derivative assets with right of offset or master netting agreements
$
292

 
$
(23
)
 
$

 
$
269

Derivative liabilities with right of offset or master netting agreements
$
(31
)
 
$
23

 
$
4

 
$
(4
)
 
 
 
 
 
 
 
 
December 31, 2014
 
 
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
536

 
$
(25
)
 
$

 
$
511

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

 
$
17

 
$

__________
(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 June 30, 2015, we had collateral totaling $6 million posted to derivative counterparties, which included $2 million of initial margin to clearinghouses or exchanges to enter into positions and $4 million of maintenance margin for changes in the fair value of those positions, to support the aggregate fair value of our net $8 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 $4 million at June 30, 2015. 
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 2015 and 2014, 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 following table presents the gross and net credit exposure from our derivative contracts as of June 30, 2015.
Counterparty Type
Gross Total
 
Net Total
 
(Millions)
Financial institutions (Investment Grade)(a)
$
292

 
$
269

Credit exposure from derivatives
$
292

 
$
269

 
__________
(a)
We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.
 
Our eight largest net counterparty positions represent approximately 99 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.
Other
Collateral support for our commodity agreements could include margin deposits, letters of credit and guarantees of payment by credit worthy parties.
Subsequent Events (Notes)
Subsequent Events [Text Block]
Subsequent Events
On July 13, 2015, we entered into a definitive merger agreement to acquire privately held RKI Exploration & Production, LLC ("RKI") for $2.75 billion, consisting of 40 million unregistered shares of WPX common stock and approximately $2.28 billion in cash (the "Acquisition"). The cash consideration is subject to closing adjustments and will be reduced by our assumption of $400 million of aggregate principal amount of RKI's senior notes and any amounts outstanding under RKI's revolving credit facility. RKI is engaged in the acquisition, exploration, development and production of oil and natural gas properties located onshore in the continental United States, concentrated primarily in the Permian Basin, and more specifically the Delaware Basin sub-area, which span parts of New Mexico and Texas. RKI also has oil and gas properties in the Powder River Basin. In connection with the Acquisition, RKI intends either (i) to contribute its Powder River Basin assets and other properties outside the Delaware Basin to a wholly owned RKI subsidiary, the ownership interests of which will be paid to RKI's equity holders in connection with the Acquisition, or (ii) to dispose of such assets in a third party sale.
The majority of RKI's Delaware Basin leasehold is located in Loving County, Texas and Eddy County, New Mexico. RKI's assets in the Permian Basin include approximately 92,000 net acres in the core of the Permian's Delaware Basin. RKI operates 659 gross producing wells in the Delaware Basin with an average working interest of approximately 93 percent. RKI's average net daily production from its Delaware Basin properties for the year ended December 31, 2014 was 18.7 MBoe per day, 43 percent of which was oil, 23 percent NGLs and 34 percent natural gas. RKI's average net daily production from its Delaware Basin properties for the three months ended March 31, 2015 was 18.5 MBoe per day, 52 percent of which was oil, 14 percent NGLs and 34 percent natural gas. As of December 31, 2014, RKI had proved reserves in the Delaware Basin of 101.5 MMBoe, 40 percent of which was oil, 25 percent NGLs and 35 percent natural gas.
WPX will fund the Acquisition with proceeds from a combination of debt, preferred stock and common stock offerings (as further described below in "Financing Transactions") along with available cash on hand and borrowings under its revolving credit facility. The parties expect to close the transaction by the end of third quarter 2015, subject to customary closing conditions.
Complete financials of RKI as of and for the period ended June 30, 2015 are not currently available to us. Certain unaudited pro forma condensed combined financial information and RKI financial statements as of March 31, 2015 and December 31, 2014 and the respective periods then ended are included in our Current Report on Form 8-K filed July 14, 2015. The unaudited pro forma condensed combined financial information was presented for illustrative purposes based on the assumptions noted therein and do not represent what our results of operations or financial position would actually have been had the transactions noted therein occurred for those periods presented.
Financing Transactions
On July 22, 2015 we completed equity offerings of (a) 30,000,000 shares of our common stock (or 34,500,000 shares if the underwriters exercise their option to purchase additional shares in full) for gross proceeds of approximately $303 million (or approximately $348 million if the underwriters exercise their option to purchase additional shares in full) at the public offering price of $10.10 per share and (b) $350 million of aggregate liquidation preference of 6.25% series A mandatory convertible preferred stock (or $402.5 million of aggregate liquidation preference if the underwriters exercise their option to purchase additional shares in full). The underwriter's have 30 days from the date of these offerings to purchase additional shares.
On July 22, 2015, we completed our debt offering of (a) $500 million aggregate principal amount of 7.50% senior unsecured notes due 2020 (the "2020 Notes") and (b) $500 million aggregate principal amount of 8.25% senior unsecured notes due 2023 (the "2023 Notes").
The Notes are the Company’s senior unsecured obligations ranking equally with the Company’s other existing and future senior unsecured indebtedness. The 2020 Notes bear interest at a rate of 7.50% per annum, and the 2023 Notes bear interest at a rate of 8.25% per annum. Interest is payable on the Notes semiannually in arrears on February 1 and August 1 of each year commencing on February 1, 2016. The 2020 Notes will mature on August 1, 2020. The 2023 Notes will mature on August 1, 2023. At any time or from time to time prior to July 1, 2020, in the case of the 2020 Notes, and June 1, 2023, in the case of the 2023 Notes, the Company may, at its option, redeem the applicable series of Notes, in whole or in part, at a makewhole redemption price as set forth in the Indenture. The Company also has the option, at any time or from time to time on or after July 1, 2020, in the case of the 2020 Notes, and June 1, 2023, in the case of the 2023 Notes, to redeem some or all of the applicable series of Notes at a redemption price equal to 100% of the principal amount of the Notes to be redeemed, as more fully described in the Indenture. The Notes are also subject to a special mandatory redemption as more fully described in the Indenture if the Company’s previously announced Acquisition is not consummated by, or the merger agreement related to such acquisition is terminated prior to, November 30, 2015. The Indenture contains covenants that, among other things, restrict the Company’s ability to grant liens on its assets and merge, consolidate or transfer or lease all or substantially all of its assets, subject to certain qualifications and exceptions.
The table below reflects the pro forma impact of the financing transactions noted above, net of estimated expenses, to certain line items of our balance sheet as of June 30, 2015.
 
June 30, 2015 As Reported
 
Financing Transaction Adjustments
 
Pro Forma After Adjustments
Cash and cash equivalents
$
317

 
$
1,608

 
$
1,925

Total assets
$
7,962

 
$
1,631

 
$
9,593

Total debt
$
2,001

 
$
1,000

 
$
3,001

Equity:
 
 
 
 
 
     Preferred stock
$

 
$
339

 
$
339

     Common stock
2

 

 
2

     Additional paid-in-capital
5,572

 
292

 
5,864

     Accumulated deficit
(1,207
)
 

 
(1,207
)
Total equity
$
4,367

 
$
631

 
$
4,998

 
 
 
 
 
 
Total liabilities and equity
$
7,962

 
$
1,631

 
$
9,593


Amendments to Credit Facility and commitment increase
On July 16, 2015, the Company amended its senior unsecured revolving credit facility to, among other things (a) modify the financial covenants in a manner favorable to the Company in respect of (i) the ratio of PV to Consolidated Indebtedness and (ii) the ratio of Consolidated Net Indebtedness to Consolidated EBITDAX and (b) add a financial covenant requiring a minimum ratio of Consolidated EBITDAX to Consolidated Interest Charges (each capitalized term used herein but not defined is defined in the Company’s revolving credit facility, as amended).
Under the amended revolving credit facility, if the Company’s Corporate Rating is (a) BB- or worse by S&P and Ba3 or worse by Moody’s or (b) B+ or worse by S&P or B1 or worse by Moody’s, the Company 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 Credit Facility, to Consolidated Indebtedness of at least 1.10 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2016 and at least 1.50 to 1.00 thereafter unless and until (i) the Company’s Corporate Rating is (A) BBB- or better with S&P (without negative outlook or negative watch) or (B) Baa3 or better by Moody’s (without negative outlook or negative watch) and (ii) the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s.
In addition, the Company is required to maintain a ratio of Consolidated Net Indebtedness to Consolidated EBITDAX of not greater than 4.50 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2016 and 4.00 to 1.00 thereafter, unless at such time the Company’s Corporate Ratings are equal to, or better than, Baa3 or BBB- by at least one of S&P and Moody’s and not less than BB+ or Ba1 by the other such agency. The ratio of Consolidated Indebtedness to Consolidated Total Capitalization is not permitted to be greater than 60 percent and is applicable for the life of the agreement. Furthermore, the Company may not permit the ratio of Consolidated EBITDAX to Consolidated Interest Charges to be less than 2.50 to 1.00.
Under the terms of the Credit Facility and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. On July 31, 2015, the commitments from existing lenders were increased by $250 million, for total commitments of $1.75 billion. Subsequent to June 30, 2015, we borrowed $200 million on the Credit Facility in anticipation of the Acquisition closing.
Powder River Divestiture Update
Subsequent to June 30, 2015, we signed agreements for the sale of our holdings in the Powder River Basin for $80 million, subject to closing adjustments such as net revenues from effective date to closing date. Based on estimated proceeds under this agreement, we expect to record a loss on sale of approximately $10 million to $20 million. Closing of this transaction is expected by the end of 2015. See Note 2 for a further discussion of Powder River operations including commitments related to certain pipeline capacity and firm gathering and treating agreements.
Discontinued Operations Discontinued Operation (Tables)
Summarized Results of Discontinued Operations
 
Three months ended June 30, 2015
 
Three months ended June 30, 2014
 
Powder River Basin
 
Powder River Basin
 
International
 
Total
 
(Millions)
Total revenues
$
17

 
$
48

 
$
39

 
$
87

Costs and expenses:
 
 
 
 
 
 
 
Lease and facility operating
$
7

 
$
10

 
$
8

 
$
18

Gathering, processing and transportation
14

 
18

 
1

 
19

Taxes other than income
1

 
2

 
7

 
9

Exploration

 

 
3

 
3

Depreciation, depletion and amortization

 
4

 
9

 
13

Impairment of assets held for sale
6

 

 

 

General and administrative

 
1

 
3

 
4

Other—net
1

 

 
2

 
2

Total costs and expenses
29

 
35

 
33

 
68

Operating income (loss)
(12
)
 
13

 
6

 
19

       Interest capitalized

 
1

 

 
1

Investment income and other
1

 

 
5

 
5

Income (loss) from discontinued operations before income taxes
(11
)
 
14

 
11

 
25

Provision (benefit) for income taxes
(4
)
 
7

 
7

 
14

Income (loss) from discontinued operations
$
(7
)
 
$
7

 
$
4

 
$
11


 
Six months ended June 30, 2015
 
Powder River Basin
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
42

 
$
15

 
$
57

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
17

 
$
4

 
$
21

Gathering, processing and transportation
28

 

 
28

Taxes other than income
4

 
3

 
7

Impairment of assets held for sale
16

 

 
16

General and administrative
1

 
1

 
2

Other—net

 

 

Total costs and expenses
66

 
8

 
74

Operating income (loss)
(24
)
 
7

 
(17
)
Investment income and other
3

 
1

 
4

Gain on sale of international assets

 
41

 
41

Income (loss) from discontinued operations before income taxes
(21
)
 
49

 
28

Provision (benefit) for income taxes (a)
(8
)
 
(3
)
 
(11
)
Income (loss) from discontinued operations
$
(13
)
 
$
52

 
$
39

__________
(a) International includes the reversal of certain U.S. deferred tax liabilities associated with Apco.

 
Six months ended June 30, 2014
 
Powder River Basin
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
110

 
$
70

 
$
180

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
21

 
$
16

 
$
37

Gathering, processing and transportation
35

 
1

 
36

Taxes other than income
8

 
13

 
21

Exploration

 
3

 
3

Depreciation, depletion and amortization
8

 
19

 
27

General and administrative
2

 
7

 
9

Other—net

 
3

 
3

Total costs and expenses
74

 
62

 
136

Operating income (loss)
36

 
8

 
44

       Interest capitalized
1

 

 
1

       Investment income and other
2

 
7

 
9

Income (loss) from discontinued operations before income taxes
39

 
15

 
54

Provision (benefit) for income taxes
15

 
9

 
24

Income (loss) from discontinued operations
$
24

 
$
6

 
$
30

Summarized Results of Discontinued Operations
 
Three months ended June 30, 2015
 
Three months ended June 30, 2014
 
Powder River Basin
 
Powder River Basin
 
International
 
Total
 
(Millions)
Total revenues
$
17

 
$
48

 
$
39

 
$
87

Costs and expenses:
 
 
 
 
 
 
 
Lease and facility operating
$
7

 
$
10

 
$
8

 
$
18

Gathering, processing and transportation
14

 
18

 
1

 
19

Taxes other than income
1

 
2

 
7

 
9

Exploration

 

 
3

 
3

Depreciation, depletion and amortization

 
4

 
9

 
13

Impairment of assets held for sale
6

 

 

 

General and administrative

 
1

 
3

 
4

Other—net
1

 

 
2

 
2

Total costs and expenses
29

 
35

 
33

 
68

Operating income (loss)
(12
)
 
13

 
6

 
19

       Interest capitalized

 
1

 

 
1

Investment income and other
1

 

 
5

 
5

Income (loss) from discontinued operations before income taxes
(11
)
 
14

 
11

 
25

Provision (benefit) for income taxes
(4
)
 
7

 
7

 
14

Income (loss) from discontinued operations
$
(7
)
 
$
7

 
$
4

 
$
11


 
Six months ended June 30, 2015
 
Powder River Basin
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
42

 
$
15

 
$
57

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
17

 
$
4

 
$
21