WPX ENERGY, INC., 10-Q filed on 11/5/2015
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2015
Nov. 4, 2015
Document Documentand Entity Information [Abstract]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Sep. 30, 2015 
 
Document Fiscal Year Focus
2015 
 
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
 
275,276,052 
Consolidated Balance Sheet (Unaudited) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Current assets:
 
 
Cash and cash equivalents
$ 99 
$ 41 
Accounts receivable, net of allowance of $5 million as of September 30, 2015 and $6 million as of December 31, 2014
298 
459 
Derivative assets, current
369 
498 
Inventories
71 
45 
Margin deposits
27 
Assets classified as held for sale, current
70 
773 
Other
28 
26 
Total current assets
937 
1,869 
Properties and equipment (successful efforts method of accounting)
15,382 
11,753 
Less—accumulated depreciation, depletion and amortization
(5,567)
(4,911)
Properties and equipment, net
9,815 
6,842 
Derivative assets, noncurrent
85 
38 
Other noncurrent assets
70 
49 
Total assets
10,907 
8,798 
Current liabilities:
 
 
Accounts payable
413 
712 
Accrued and other current liabilities
283 
177 
Liabilities of disposal group associated with assets held for sale
132 
Deferred income taxes, current
65 
151 
Derivative liabilities, current
10 
37 
Total current liabilities
772 
1,209 
Deferred income taxes
1,255 
621 
Long-term debt
3,400 
2,280 
Derivative liabilities, noncurrent
Asset retirement obligations
230 
198 
Other noncurrent liabilities (Note 3)
176 
57 
Stockholders’ equity:
 
 
Preferred stock (100 million shares authorized at $0.01 par value; 7 million shares issued at September 30, 2015)
339 
Common stock (2 billion shares authorized at $0.01 par value; 275.3 million shares issued at September 30, 2015 and 203.7 million shares issued at December 31, 2014)
Additional paid-in-capital
6,167 
5,562 
Accumulated deficit
(1,437)
(1,244)
Accumulated other comprehensive income (loss)
(1)
Total stockholders’ equity
5,072 
4,319 
Noncontrolling interests in consolidated subsidiaries
109 
Total equity
5,072 
4,428 
Total liabilities and equity
$ 10,907 
$ 8,798 
Consolidated Balance Sheet (Unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 5 
$ 6 
Preferred stock, par value
$ 0.01 
$ 0.01 
Preferred stock, shares authorized
100,000,000 
100,000,000 
Preferred stock, shares issued
7,000,000 
Common stock, par value
$ 0.01 
$ 0.01 
Common stock, shares authorized
2,000,000,000 
2,000,000,000 
Common stock, shares issued
275,300,000 
203,700,000 
Consolidated Statement of Operations (Unaudited) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Product revenues:
 
 
 
 
Natural gas sales
$ 146 
$ 201 
$ 440 
$ 780 
Oil and condensate sales
124 
199 
386 
542 
Natural gas liquid sales
24 
53 
72 
168 
Total product revenues
294 
453 
898 
1,490 
Gas management
35 
145 
250 
937 
Net gain (loss) on derivatives (Note 12)
205 
148 
239 
(64)
Other
Total revenues
537 
747 
1,393 
2,368 
Costs and expenses:
 
 
 
 
Lease and facility operating
50 
63 
158 
182 
Gathering, processing and transportation
75 
82 
217 
249 
Taxes other than income
17 
32 
58 
100 
Gas management, including charges for unutilized pipeline capacity (Note 5)
43 
164 
211 
788 
Exploration (Note 5)
56 
28 
69 
97 
Depreciation, depletion and amortization
242 
201 
685 
596 
Net (gain) loss on sales of assets
(1)
(279)
Loss On Sale Of Working Interests
196 
General and administrative
54 
71 
181 
208 
Acquisition Costs
23 
23 
Other—net
38 
Total costs and expenses
566 
645 
1,361 
2,422 
Operating income (loss)
(29)
102 
32 
(54)
Interest expense (Note 2)
(65)
(31)
(130)
(88)
Loss on extinguishment of acquired debt
(65)
(65)
Investment income and other
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest
(158)
71 
(160)
(142)
Provision (benefit) for income taxes
(52)
25 
(53)
(44)
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest
(106)
46 
(107)
(98)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
(124)
20 
(85)
50 
Net income (loss)
(230)
66 
(192)
(48)
Less: Net income (loss) attributable to noncontrolling interests
Comprehensive Income (Loss), Net of Tax, Attributable to Parent
(230)
62 
(193)
(55)
Preferred Stock Dividends, Income Statement Impact
Net Income (Loss) Available to Common Stockholders, Basic
(234)
62 
(197)
(55)
Income (Loss) from Continuing Operations Attributable to Parent
(110)
46 
(111)
(98)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent
$ (124)
$ 16 
$ (86)
$ 43 
Income (Loss) from Continuing Operations, Per Basic and Diluted Share
$ (0.44)
$ 0.23 
$ (0.50)
$ (0.48)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share
$ (0.49)
$ 0.07 
$ (0.39)
$ 0.21 
Earnings Per Share, Basic and Diluted
$ (0.93)
$ 0.30 
$ (0.89)
$ (0.27)
Weighted Average Number of Shares Outstanding, Basic
251.2 
203.3 
220.3 
202.5 
Weighted Average Number of Shares Outstanding, Diluted
251.2 1
207.5 1
220.3 1
202.5 1
Consolidated Statement of Changes in Equity (Unaudited) (USD $)
In Millions, unless otherwise specified
Total
Preferred Stock
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)
(192)
 
 
 
 
 
 
 
Comprehensive Income (Loss) Attributable to Parent
 
 
 
 
(193)
 
(193)
 
Net Income (Loss) Attributable to Noncontrolling Interest
 
 
 
 
 
 
Comprehensive income (loss)
(192)
 
 
 
 
 
 
 
Stock based compensation
18 
 
 
18 
 
 
18 
 
Stock Issued During Period, Value, New Issues
292 
 
 
292 
 
 
292 
 
Stock Issued During Period, Value, Acquisitions
296 
 
295 
 
 
296 
 
Proceeds from Issuance of Preferred Stock and Preference Stock
339 
339 
 
 
 
 
339 
 
Decrease in Noncontrolling Interest and Accumulated Other Comprehensive Income Due To Deconsolidation
(109)
 
 
 
 
 
 
 
September 30, 2015 at Sep. 30, 2015
$ 5,072 
$ 339 
$ 3 
$ 6,167 
$ (1,437)
$ 0 
$ 5,072 
$ 0 1
Consolidated Statement of Changes in Equity (Parenthetical)
Sep. 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
9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Operating Activities
 
 
Net income (loss)
$ (192)
$ (48)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation Depletion And Amortization Including Discontinued Portion
685 
638 
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations
(138)
(55)
Provision for impairment of properties and equipment (including certain exploration expenses)
78 
95 
Amortization of stock-based awards
27 
26 
Gains (Losses) on Extinguishment of Debt
81 
Gain (Loss) on Disposition of Assets
(317)
195 
Cash provided (used) by operating assets and liabilities:
 
 
Accounts receivable
232 
71 
Inventories
(11)
Margin deposits and customer margin deposits payable
25 
(22)
Other current assets
16 
Accounts payable
(186)
(15)
Accrued and other current liabilities
22 
(22)
Changes in current and noncurrent derivative assets and liabilities
183 
(106)
Other, including changes in other noncurrent assets and liabilities
140 
Net cash provided by operating activities
629 
779 
Investing Activities
 
 
Capital expenditures
(890)1
(1,325)1
Proceeds from sale of assets
819 
389 
Payments to Acquire Investments
1,190 
Other
(3)
Net cash provided by (used in) investing activities
(1,259)
(939)
Financing Activities
 
 
Proceeds from common stock
295 
15 
Proceeds from Preferred Stock
339 
Proceeds from Issuance of Long-term Debt
1,000 
500 
Borrowings on credit facility
756 
1,451 
Payments on credit facility
(636)
(1,816)
Payments for Deposits Applied to Debt Retirements
(1,055)
Payments of Debt Issuance Costs
(40)
(6)
Other
(12)
Net cash provided by (used in) financing activities
659 
132 
Net increase (decrease) in cash and cash equivalents
29 
(28)
Effect of Exchange Rate on Cash and Cash Equivalents
(6)
Cash and cash equivalents at end of period
99 
 
Cash and Cash Equivalents, at Carrying Value, Including Discontinued Operations
70 2
99 2
Increase to properties and equipment
(640)
(1,389)
Changes in related accounts payable and accounts receivable
$ (250)
$ 64 
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, North Dakota and Texas in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins and we have recently entered the core of the Permian's Delaware Basin through our acquisition of RKI Exploration & Production, LLC ("RKI"). See Note 2 for additional information regarding this acquisition. 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 had operations in the Powder River Basin in Wyoming which were sold on September 1, 2015 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 September 30, 2015, results of operations for the three and nine months ended September 30, 2015 and 2014, changes in equity for the nine months ended September 30, 2015 and cash flows for the nine months ended September 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 September 1, 2015, we completed the sale of our Powder River Basin operations in Wyoming. The results of operations of the Powder River Basin have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheet as of December 31, 2014.
On January 29, 2015, we completed the disposition of our international interests. 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.
See Note 3 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 9 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 Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 September 30, 2015, we have $47 million in debt issuance costs which is reported in Other noncurrent assets on the Consolidated Balance Sheets.
In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments that eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Under the ASU, acquirers must recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts they would have recorded in previous periods if the accounting had been completed at the acquisition date. The ASU does not change the criteria for determining whether an adjustment qualifies as a measurement-period adjustment and does not change the length of the measurement period. ASU 2015-16 is effective for the annual reporting period beginning after December 15, 2015, including interim period within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been made available for issuance. The Company is currently evaluating the impact, if any, of ASU 2015-16 to the Company's financial position, results of operations or cash flows.
Acquisitions (Notes)
Acquisition [Text Block]
Acquisition
On August 17, 2015, we completed the acquisition of privately held RKI. Per the terms of the merger agreement, the purchase price was $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 was subject to closing adjustments and was reduced by our assumption of $400 million of aggregate principal amount of RKI's senior notes and amounts outstanding under RKI's revolving credit facility along with other working capital items. The closing adjustments are subject to change as closing estimates are finalized. We incurred approximately $23 million of acquisition-related costs, primarily related to legal and advisory fees which are reflected on a separate line item on the Consolidated Statements of Operations. In addition, we incurred $16 million of acquisition bridge facility fees, included in interest expense and a $65 million loss on extinguishment of RKI's senior notes, reflected as a separate line in the Consolidated Statements of Operations.
RKI was 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 had oil and gas properties in the Powder River Basin. In connection with the Acquisition, RKI contributed its Powder River Basin assets and other properties outside the Delaware Basin to a wholly owned RKI subsidiary, the ownership interests of which were distributed to RKI's equity holders in connection with the Acquisition. Thus, we acquired RKI exclusive of the Powder River Basin assets and other properties outside the Delaware Basin.
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 operated 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. As of December 31, 2014, RKI reported 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 funded the Acquisition with proceeds from a combination of debt, preferred stock and common stock offerings along with available cash on hand and borrowings under its revolving credit facility. See Notes 7 and 10 for further discussion on the financing of this transaction.
The following table presents the unaudited pro forma financial results for the nine months ended September 30, 2015 and 2014 as if the Acquisition and related financings had been completed January 1, 2014. In addition, the nine months ended September 30, 2015 have been adjusted to exclude $23 million of acquisition costs, $65 million loss on extinguishment of acquired debt and $16 million of acquisition bridge facility fees. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Acquisition occurred on the date assumed or for the periods presented, nor is such information indicative of the Company's expected future results of operations.
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
 
 
(millions)
Revenues
 
$
1,606

 
$
2,618

Net income (loss) from continuing operations attributable to WPX Energy, Inc.
 
$
(21
)
 
$
(80
)

The Acquisition qualified as a business combination, and as a result, we must estimate the fair value of the underlying shares distributed, the assets acquired and the liabilities assumed as of the August 17, 2015 Acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. We will use a combination of market data, discounted cash flow models and replacement estimates in determining the fair value of the oil and gas properties and the related midstream assets. All of which will include estimates and assumptions such as future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs. Deferred taxes must also be recorded for any differences between the assigned values and tax bases of assets and liabilities.  Estimated deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and loss carryforwards at the Acquisition date, although such estimates may change in the future as additional information becomes known.
The initial accounting for the Acquisition is preliminary and adjustments to provisional amounts for properties and equipment, certain accrued receivables and liabilities and related deferred taxes or recognition of additional assets acquired or liabilities assumed may occur as additional information is obtained about facts and circumstances that existed at the Acquisition date. In addition, the cash consideration is subject to change due to post-closing adjustments to the working capital estimates at the time of closing. Such adjustments could result in the recognition of goodwill which would be subject to impairment review. The following table summarizes the consideration paid for the Acquisition and the preliminary estimates of fair value of the assets acquired and liabilities assumed as of the Acquisition date. The purchase price allocation is preliminary and subject to adjustment, specifically post-closing working capital adjustments, finalization of the valuation of oil and gas properties and midstream assets and deferred taxes. These amounts will be finalized as soon as possible, but no later than September 30, 2016.
 
 
 Purchase Price Allocation
 
 
(Millions)
Consideration:
 
 
Cash
 
$
1,263

Fair value of WPX common stock issued
 
296

Total consideration
 
$
1,559

Fair value of liabilities assumed:
 
 
Accounts payable
 
$
90

Accrued liabilities
 
77

Deferred income taxes, current
 
34

Deferred income taxes, noncurrent
 
646

Long-term debt
 
990

Asset retirement obligation
 
22

Total liabilities assumed as of September 30, 2015
 
1,859

Fair value of assets acquired:
 
 
Cash and cash equivalents
 
51

Accounts receivable, net
 
75

Derivative assets, current
 
97

Derivative assets, noncurrent
 
34

Inventories
 
14

Other current assets
 
3

Properties and equipment
 
3,140

Other noncurrent assets
 
4

Total assets acquired as of September 30, 2015
 
3,418

Net fair values
 
$
1,559

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.
In August 2015 we signed agreements for the sale of our Powder River Basin for $80 million, subject to closing adjustments. On September 1, 2015, we completed a portion of the Powder River Basin divestiture. The remaining portion of the divestiture, which relates to our equity method investment in Fort Union Gas Gathering, LLC, closed on October 30, 2015. We recorded a pretax loss of $15 million related to this transaction during third quarter 2015. During the first and second quarters of 2015, we recorded a total of $16 million in impairments of the net assets to a probability weighted-average of expected sales prices for the Powder River Basin. In addition, we retained certain firm gathering and treating obligations related to the Powder River properties sold with total commitments of $104 million through 2020. These commitments had been in excess of our production throughput. We also have certain pipeline capacity obligations held by our marketing company with total commitments through 2021 totaling $150 million, which were related to the Powder River Operation. With the closing of the Powder River Basin sale and exiting this basin, we recorded $187 million of expense related to these contracts and included as a separate line below. This $187 million expense is the estimated present value of the remaining $254 million in payments associated with these contracts as of the Powder River Basin sales date, and includes the fair value of estimated recoveries from potential third parties and discounting based on our risk adjusted borrowing rate. Offsetting liabilities of $54 million and $133 million are recorded in accrued and other current liabilities and other noncurrent liabilities, respectively.
During the third quarter of 2014, we had signed an agreement to sell our Powder River Basin holdings. This sales agreement did not successfully close in March 2015 and we subsequently terminated the transaction with the counterparty. During third quarter 2015, we received $13 million in escrow funds as a result of the terminated contract and this amount is included in Other-net expense below.
Summarized Results of Discontinued Operations
 
Three months ended September 30, 2015
 
Three months ended September 30, 2014
 
Powder River Basin
 
Powder River Basin
 
International
 
Total
 
(Millions)
Total revenues
$
12

 
$
41

 
$
47

 
$
88

Costs and expenses:
 
 
 
 
 
 
 
Lease and facility operating
$
6

 
$
11

 
$
10

 
$
21

Gathering, processing and transportation
10

 
16

 

 
16

Taxes other than income
1

 
4

 
8

 
12

Exploration

 

 
1

 
1

Depreciation, depletion and amortization

 
3

 
12

 
15

General and administrative
4

 
1

 
4

 
5

Accrual for contract obligations retained
187

 

 

 

Other—net
(14
)
 

 

 

Total costs and expenses
194

 
35

 
35

 
70

Operating income (loss)
(182
)
 
6

 
12

 
18

Investment income and other
2

 
2

 
6

 
8

Loss on sale of Powder River Basin
(15
)
 

 

 

Income (loss) from discontinued operations before income taxes
(195
)
 
8

 
18

 
26

Provision (benefit) for income taxes
(71
)
 
2

 
4

 
6

Income (loss) from discontinued operations
$
(124
)
 
$
6

 
$
14

 
$
20


 
Nine months ended September 30, 2015
 
Powder River Basin
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
54

 
$
15

 
$
69

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
23

 
$
4

 
$
27

Gathering, processing and transportation
38

 

 
38

Taxes other than income
5

 
3

 
8

Impairment of assets held for sale
16

 

 
16

General and administrative
5

 
1

 
6

Accrual for contract obligations retained
187

 

 
187

Other—net
(14
)
 

 
(14
)
Total costs and expenses
260

 
8

 
268

Operating income (loss)
(206
)
 
7

 
(199
)
Investment income and other
5

 
1

 
6

Loss on sale of Powder River Basin
(15
)
 

 
(15
)
Gain on sale of international assets

 
41

 
41

Income (loss) from discontinued operations before income taxes
(216
)
 
49

 
(167
)
Provision (benefit) for income taxes (a)
(79
)
 
(3
)
 
(82
)
Income (loss) from discontinued operations
$
(137
)
 
$
52

 
$
(85
)
__________
(a) International includes the reversal of certain U.S. deferred tax liabilities associated with Apco.

 
Nine months ended September 30, 2014
 
Powder River Basin
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
151

 
$
117

 
$
268

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
32

 
$
26

 
$
58

Gathering, processing and transportation
51

 
1

 
52

Taxes other than income
12

 
21

 
33

Exploration

 
4

 
4

Depreciation, depletion and amortization
11

 
31

 
42

General and administrative
3

 
11

 
14

Other—net

 
3

 
3

Total costs and expenses
109

 
97

 
206

Operating income (loss)
42

 
20

 
62

       Investment income and other
5

 
13

 
18

Income (loss) from discontinued operations before income taxes
47

 
33

 
80

Provision (benefit) for income taxes
17

 
13

 
30

Income (loss) from discontinued operations
$
30

 
$
20

 
$
50


Assets and Liabilities Classified as Held for Sale on the Consolidated Balance Sheet

As of September 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 investment in Fort Union Gas Gathering, LLC and Van Hook gathering system.
 
September 30, 2015
 
Total
 
(Millions)
Assets classified as held for sale
 
Investments in Fort Union Gas Gathering, LLC
$
16

Total assets classified as held for sale—discontinued operations
$
16

Total assets classified as held for sale—continuing operations (Note 5)
54

Total assets classified as held for sale on the Consolidated Balance Sheets
$
70

 
 
Liabilities associated with assets held for sale
 
Total liabilities associated with assets held for sale—continuing operations (Note 5)
$
1

Total liabilities associated with assets held for sale on the Consolidated Balance Sheets
$
1



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 5)
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 5)
$
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 $12 million for the nine months ended September 30, 2015 and total cash provided by operating activities was $58 million for the nine months ended September 30, 2014. Total cash used in investing activities related to Powder River Basin discontinued operations was $4 million and $9 million for the nine months ended September 30, 2015 and 2014, respectively. Cash provided by operating activities related to our international operations was $3 million and $77 million for the nine months ended September 30, 2015 and 2014, respectively. Total cash used in investing activities related to our international operations was $15 million and $61 million for the nine months ended September 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 September 30,
 
Nine months
ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc.
$
(106
)
 
$
46

 
$
(107
)
 
$
(98
)
Less: Dividends on preferred stock
$
4

 
$

 
$
4

 
$

Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
$
(110
)
 
$
46

 
$
(111
)
 
$
(98
)
Basic weighted-average shares
251.2

 
203.3

 
220.3

 
202.5

Effect of dilutive securities:
 
 
 
 
 
 
 
Nonvested restricted stock units and awards

 
3.2

 

 

Stock options

 
1.0

 

 

Diluted weighted-average shares(a)
251.2

 
207.5

 
220.3

 
202.5

Earnings (loss) per common share from continuing operations:
 
 
 
 
 
 
 
Basic
$
(0.44
)
 
$
0.23

 
$
(0.50
)
 
$
(0.48
)
Diluted
$
(0.44
)
 
$
0.23

 
$
(0.50
)
 
$
(0.48
)

__________
(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. available to common stockholders.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Weighted-average nonvested restricted stock units and awards
0.7

 

 
1.4

 
2.8

Weighted-average stock options
0.1

 

 
0.1

 
1.0

Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 10)
26.7

 

 
9.0

 


The table below includes information related to stock options that were outstanding at September 30, 2015 and 2014 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,
 
2015
 
2014
Options excluded (millions)
2.6

 

Weighted-average exercise price of options excluded
$
16.16

 
$

Exercise price range of options excluded
$11.46 - $21.81

 

Third quarter weighted-average market price
$
8.36

 
$
23.67



For the nine months ended September 30, 2015, approximately 1.1 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, Exploration Expenses And Other Accruals [Text Block]
Asset Sales, Other Expenses and Exploration Expenses
Asset Sales
During August 2015, we agreed to sell a North Dakota gathering system for approximately $185 million, subject to closing adjustments, to a private equity fund managed by the Ares EIF Group, a subsidiary of Ares Management, L.P. (NYSE: ARES). Under the terms of the agreement, a subsidiary of the buyer, Midstream Capital Partners, will manage the overall system and we will operate the system which currently gathers approximately 11,000 barrels per day of oil, approximately 6,500 Mcf per day of natural gas and approximately 5,000 barrels per day of water. Closing of this transaction is expected in the fourth quarter of 2015.
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 us 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 of $17 million, 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 in the second quarter of 2014. An additional $1 million loss on sale was recorded in the third quarter of 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 September 30,
 
Nine months
ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Geologic and geophysical costs
$
3

 
$
1

 
$
5

 
$
8

Dry hole costs and impairments of exploratory area well costs
22

 
6

 
22

 
21

Unproved leasehold property impairment, amortization and expiration
31

 
21

 
42

 
68

Total exploration expenses
$
56

 
$
28

 
$
69

 
$
97


For both the three and nine months ended September 30, 2015, dry hole costs and impairments of exploratory area well costs and unproved leasehold property impairment, amortization and expiration include $21 million and $26 million, respectively, related to a non-core exploratory play where we no longer intend to continue exploration activities.
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 an exploratory area where management had determined to cease exploratory activities. The remaining amount represents dry hole costs associated with exploratory wells where hydrocarbons were not detected.
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 non-core exploratory areas where we no longer intend to continue exploration activities.
As of September 30, 2015, our total capitalized well costs associated with our exploratory areas, including the Niobrara Shale in the Piceance Basin, totaled approximately $74 million.
Inventories
Inventories
Inventories
The following table presents a summary of our inventories as of the dates indicated below.
 
September 30,
2015
 
December 31,
2014
 
(Millions)
Material, supplies and other
$
68

 
$
43

Crude oil production in transit
3

 
2

     Total inventories
$
71

 
$
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.
 
September 30,
2015
 
December 31,
2014
 
(Millions)
5.250% Senior Notes due 2017
$
400

 
$
400

7.500% Senior Notes due 2020
500

 

6.000% Senior Notes due 2022
1,100

 
1,100

8.250% Senior Notes due 2023
500

 

5.250% Senior Notes due 2024
500

 
500

Credit facility agreement
400

 
280

Other
1

 
1

     Total debt
$
3,401

 
$
2,281

Less: Current portion of long-term debt
1

 
1

     Total long-term debt
$
3,400

 
$
2,280


Senior Notes
On July 22, 2015, we completed our debt offering of (a) $500 million aggregate principal amount of 7.500% senior unsecured notes due 2020 (the "2020 Notes") and (b) $500 million aggregate principal amount of 8.250% 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 7.500% per annum, and the 2023 Notes bear interest at a rate of 8.250% 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 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.
See 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
Including the impact of amendments in July 2015, we have a $1.75 billion five-year senior unsecured revolving credit facility agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). 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.
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. As of the date of this filing our credit rating with S&P was BB, positive outlook and our credit rating with Moody's is Ba1, negative outlook.
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.
On July 31, 2015, the commitments from existing lenders were increased by $250 million, for total commitments of $1.75 billion.
As of September 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.
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 September 30, 2015, a total of $239 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 September 30,
 
Nine months
ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Current:
 
 
 
 
 
 
 
Federal
$
(4
)
 
$
(2
)
 
$
(4
)
 
$
10

State
1

 
(2
)
 
1

 

 
(3
)
 
(4
)
 
(3
)
 
10

Deferred:
 
 
 
 
 
 
 
Federal
(46
)
 
26

 
(47
)
 
(60
)
State
(3
)
 
3

 
(3
)
 
6

 
(49
)
 
29

 
(50
)
 
(54
)
Total provision (benefit)
$
(52
)
 
$
25

 
$
(53
)
 
$
(44
)

For the three and nine months ended September 30, 2015, the effective rate differs from the federal statutory rate due to the effects of state income taxes and certain nondeductible acquisition costs.
The effective tax rate for the three and nine months ended September 30, 2014 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 September 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 our spin-off from Williams on December 31, 2011. 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 Colorado 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 2008 through September 2015, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $114 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 September 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 September 30, 2015 and December 31, 2014, the Company had accrued approximately $18 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, 2015
 
December 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$
3

 
$
451

 
$

 
$
454

 
$
14

 
$
517

 
$
5

 
$
536

Energy derivative liabilities
$
4

 
$
8

 
$

 
$
12

 
$
32

 
$
10

 
$

 
$
42

Total debt(a)
$

 
$
3,031

 
$

 
$
3,031

 
$

 
$
2,218

 
$

 
$
2,218

__________
(a)
The carrying value of total debt, excluding capital leases, was $3,400 million and $2,280 million as of September 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 extends through the end of 2018. 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 less than $1 million at September 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 September 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.
 
 
 
 
Stockholder's Equity (Notes)
Stockholders' Equity Note Disclosure [Text Block]
Stockholders’ Equity
On July 22, 2015 we completed equity offerings of (a) 30 million shares of our common stock for gross proceeds of approximately $303 million, before underwriter discounts and commissions of $10.5 million, 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 ("Mandatory Convertible Preferred Stock") as further described below.
On August 17, 2015 we issued 40 million unregistered shares of our common stock to RKI shareholders as part of the consideration under our merger agreement. The estimated fair value of the shares was $296 million. See Note 2 for further discussion of the Acquisition.
Common Stock
Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare on our common stock out of funds legally available for the payment of dividends. No dividends on our common stock were declared or paid for 2015 or 2014. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
Subject to certain exceptions, so long as any share of our Mandatory Convertible Preferred Stock remains outstanding, no dividend or distribution shall be declared or paid on the shares of the Company’s common stock or any other class or series of junior stock, and no common stock or any other class or series of junior or parity stock shall be purchased, redeemed or otherwise acquired for consideration by the Company or any of its subsidiaries unless all accumulated and unpaid dividends for all preceding dividend periods have been declared and paid upon, or a sufficient sum of cash or number of shares of the Company’s common stock has been set apart for the payment of such dividends upon, all outstanding shares of Mandatory Convertible Preferred Stock
Preferred Stock
Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding. As of September 30, 2015 there were 7 million shares of our 6.25% series A Mandatory Convertible Preferred Stock (as described below) issued and outstanding.
Series A Mandatory Convertible Preferred Stock
On July 22, 2015, we issued 7 million shares, $0.01 par value, pursuant to a registered public offering, of our 6.25% Series A Mandatory Convertible Preferred Stock (“Mandatory Convertible Preferred Stock”) at $50 per share, for gross proceeds of approximately $350 million, before underwriting discounts and commissions of $10.5 million. The underwriters did not exercise their option to purchase additional shares.
Dividends on our Mandatory Convertible Preferred Stock will be payable on a cumulative basis when, as and if declared by our board of directors, or an authorized committee of our board of directors, at an annual rate of 6.25% of the liquidation preference of $50 per share. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock, or in any combination of cash and shares of our common stock on January 31, April 30, July 31 and October 31 of each year, commencing on October 31, 2015 and ending on, and including, July 31, 2018.
Each share of our Mandatory Convertible Preferred Stock has a liquidation preference of $50 pursuant to the Certificate of Designations and unless converted or redeemed earlier each share of our Mandatory Convertible Preferred Stock will automatically convert on the mandatory conversion date, which is the third business day immediately following the last trading day of the final averaging period into between 4.1254 and 4.9504 shares of our common stock (respectively, the “minimum conversion rate” and “maximum conversion rate”), subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion will be determined based on the average volume weighted average price per share of our common stock over the 20 consecutive trading day period beginning on, and including, the 23rd scheduled trading day immediately preceding July 31, 2018, which we refer to as the “final averaging period.” Other than during a fundamental change conversion period, at any time prior to July 31, 2018, a holder may convert one share of our Mandatory Convertible Preferred Stock into a number of shares of our common stock equal to the minimum conversion rate of 4.1254, subject to anti-dilution adjustments. If a holder converts one share of our Mandatory Convertible Preferred Stock during a specified period beginning on the effective date of a fundamental change (as described in the offering documents), the conversion rate will be adjusted under certain circumstances, and such holder will also be entitled to a make-whole dividend amount (as described in the offering documents).
On October 2, 2015 our Board of Directors approved a quarterly dividend of $0.85938 per share to holders of our Mandatory Convertible Preferred Stock. The dividend was paid on November 2, 2015, to holders of record of our Mandatory Convertible Preferred Stock at the close of business on October 15, 2015.
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 put options which guarantee a minimum price sold, call options which limit value to a ceiling price, zero-cost collars which guarantee value between a floor and ceiling price, or swaptions which convert to a swap when market price exceeds a ceiling price.
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 September 30, 2015.
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
Oct -Dec 2015
 
Fixed Price Swaps
 
Henry Hub
 
(435
)
 
$
4.06

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

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

Natural Gas
 
2016
 
Fixed Price Swaps
 
Henry Hub
 
(412
)
 
$
3.63

Natural Gas
 
2016
 
Swaptions
 
Henry Hub
 
(90
)
 
$
4.23

Natural Gas
 
2016
 
Basis Swaps
 
NGPL
 
(5
)
 
$
(0.23
)
Natural Gas
 
2016
 
Basis Swaps
 
Permian
 
(10
)
 
$
(0.19
)
Natural Gas
 
2016
 
Basis Swaps
 
Rockies
 
(90
)
 
$
(0.24
)
Natural Gas
 
2016
 
Basis Swaps
 
San Juan
 
(60
)
 
$
(0.19
)
Natural Gas
 
2016
 
Basis Swaps
 
SoCal
 
(18
)
 
$
(0.03
)
Natural Gas
 
2017
 
Fixed Price Swaps
 
Henry Hub
 
(93
)
 
$
3.22

Natural Gas
 
2017
 
Fixed Price Calls
 
Henry Hub
 
(16
)
 
$
4.50

Natural Gas
 
2017
 
Swaptions
 
Henry Hub
 
(65
)
 
$
4.19

Natural Gas
 
2018
 
Fixed Price Calls
 
Henry Hub
 
(16
)
 
$
4.75

Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
Oct -Dec 2015
 
Fixed Price Swaps
 
WTI
 
(30,146
)
 
$
85.63

Crude Oil
 
Oct -Dec 2015
 
Basis Swaps
 
Midland- Cushing
 
(5,000
)
 
$
0.30

Crude Oil
 
2016
 
Fixed Price Swaps
 
WTI
 
(25,049
)
 
$
62.22

Crude Oil
 
2016
 
Basis Swaps
 
Midland- Cushing
 
(5,000
)
 
$
(0.45
)
Crude Oil
 
2016
 
Swaptions
 
WTI
 
(8,500
)
 
$
84.27

Crude Oil
 
2017
 
Fixed Price Swaps
 
WTI
 
(5,554
)
 
$
65.30

__________
(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, calls, 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 September 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
 
Oct -Dec 2015
 
Index
 
Multiple
 
(39
)
__________
(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.
 
September 30, 2015
 
December 31, 2014
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production
$
451

 
$
8

 
$
517

 
$
10

Derivatives related to physical marketing agreements
3

 
4

 
19

 
32

Total derivatives
$
454

 
$
12

 
$
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 September 30,
 
Nine months
ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Gain (loss) from derivatives related to production (a)
$
206

 
$
150

 
$
260

 
$
40

Gain (loss) from derivatives related to physical marketing agreements (b)
(1
)
 
(2
)
 
(21
)
 
(104
)
Net gain (loss) on derivatives not designated as hedges
$
205

 
$
148

 
$
239

 
$
(64
)

(a)
Includes receipts totaling $159 million and $10 million for settlements of derivatives during the three months ended September 30, 2015 and 2014, respectively; and receipts totaling $454 million and payments totaling $57 million for the nine months ended September 30, 2015 and 2014, respectively.
(b)
Includes payments totaling $4 million and receipts totaling $5 million for settlements of derivatives during the three months ended September 30, 2015 and 2014, respectively; and payments totaling $32 million and $114 million for the nine months ended September 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
September 30, 2015
(Millions)
Derivative assets with right of offset or master netting agreements
$
454

 
$
(11
)
 
$

 
$
443

Derivative liabilities with right of offset or master netting agreements
$
(12
)
 
$
11

 
$
1

 
$

 
 
 
 
 
 
 
 
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 September 30, 2015, we had collateral totaling $1 million posted to derivative counterparties, which includes $1 million of maintenance margin for changes in the fair value of those positions, to support the aggregate fair value of our net $1 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. There would have been no 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, at September 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 September 30, 2015.
Counterparty Type
Gross Total
 
Net Total
 
(Millions)
Financial institutions (Investment Grade)(a)
$
455

 
$
444

Credit reserves
(1
)
 
(1
)
Credit exposure from derivatives
$
454

 
$
443

 
__________
(a)
We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.
 
Our nine largest net counterparty positions represent approximately 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.
Acquisitions (Tables)
The following table summarizes the consideration paid for the Acquisition and the preliminary estimates of fair value of the assets acquired and liabilities assumed as of the Acquisition date. The purchase price allocation is preliminary and subject to adjustment, specifically post-closing working capital adjustments, finalization of the valuation of oil and gas properties and midstream assets and deferred taxes. These amounts will be finalized as soon as possible, but no later than September 30, 2016.
 
 
 Purchase Price Allocation
 
 
(Millions)
Consideration:
 
 
Cash
 
$
1,263

Fair value of WPX common stock issued
 
296

Total consideration
 
$
1,559

Fair value of liabilities assumed:
 
 
Accounts payable
 
$
90

Accrued liabilities
 
77

Deferred income taxes, current
 
34

Deferred income taxes, noncurrent
 
646

Long-term debt
 
990

Asset retirement obligation
 
22

Total liabilities assumed as of September 30, 2015
 
1,859

Fair value of assets acquired:
 
 
Cash and cash equivalents
 
51

Accounts receivable, net
 
75

Derivative assets, current
 
97

Derivative assets, noncurrent
 
34

Inventories
 
14

Other current assets
 
3

Properties and equipment
 
3,140

Other noncurrent assets
 
4

Total assets acquired as of September 30, 2015
 
3,418

Net fair values
 
$
1,559

The following table presents the unaudited pro forma financial results for the nine months ended September 30, 2015 and 2014 as if the Acquisition and related financings had been completed January 1, 2014. In addition, the nine months ended September 30, 2015 have been adjusted to exclude $23 million of acquisition costs, $65 million loss on extinguishment of acquired debt and $16 million of acquisition bridge facility fees. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Acquisition occurred on the date assumed or for the periods presented, nor is such information indicative of the Company's expected future results of operations.
 
 
Nine Months Ended September 30,
 
 
2015
 
2014
 
 
(millions)
Revenues
 
$
1,606

 
$
2,618

Net income (loss) from continuing operations attributable to WPX Energy, Inc.
 
$
(21
)
 
$
(80
)
Discontinued Operations Discontinued Operation (Tables)
Summarized Results of Discontinued Operations
 
Three months ended September 30, 2015
 
Three months ended September 30, 2014
 
Powder River Basin
 
Powder River Basin
 
International
 
Total
 
(Millions)
Total revenues
$
12

 
$
41

 
$
47

 
$
88

Costs and expenses:
 
 
 
 
 
 
 
Lease and facility operating
$
6

 
$
11

 
$
10

 
$
21

Gathering, processing and transportation
10

 
16

 

 
16

Taxes other than income
1

 
4

 
8

 
12

Exploration

 

 
1

 
1

Depreciation, depletion and amortization

 
3

 
12

 
15

General and administrative
4

 
1

 
4

 
5

Accrual for contract obligations retained
187

 

 

 

Other—net
(14
)
 

 

 

Total costs and expenses
194

 
35

 
35

 
70

Operating income (loss)
(182
)
 
6

 
12

 
18

Investment income and other
2

 
2

 
6

 
8

Loss on sale of Powder River Basin
(15
)
 

 

 

Income (loss) from discontinued operations before income taxes
(195
)
 
8

 
18

 
26

Provision (benefit) for income taxes
(71
)
 
2

 
4

 
6

Income (loss) from discontinued operations
$
(124
)
 
$
6

 
$
14

 
$
20


 
Nine months ended September 30, 2015
 
Powder River Basin
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
54

 
$
15

 
$
69

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
23

 
$
4

 
$
27

Gathering, processing and transportation
38