WPX ENERGY, INC., 8-K filed on 5/25/2016
Current report filing
Document and Entity Information
12 Months Ended
Dec. 31, 2015
Document Documentand Entity Information [Abstract]
 
Document Type
8-K 
Amendment Flag
false 
Document Period End Date
Dec. 31, 2015 
Entity Registrant Name
WPX ENERGY, INC. 
Entity Central Index Key
0001518832 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Current assets:
 
 
Cash and cash equivalents
$ 38 
$ 41 
Accounts receivable, net of allowance of $6 million as of December 31, 2015 and December 31, 2014
300 
437 
Derivative assets
308 
498 
Inventories
46 
31 
Margin deposits
27 
Disposal Group, Including Discontinued Operation, Assets, Current
178 
930 
Other
22 
23 
Total current assets
893 
1,987 
Properties and equipment, net (successful efforts method of accounting)
6,522 
3,395 
Derivative assets
51 
24 
Disposal Group, Including Discontinued Operation, Assets, Noncurrent
894 
3,464 
Other noncurrent assets
33 
26 
Total assets
8,393 
8,896 
Current liabilities:
 
 
Accounts payable
278 
638 
Accrued Liabilities and Other Liabilities
302 
145 
Disposal Group, Including Discontinued Operation, Liabilities, Current
140 
357 
Deferred Tax Liabilities, Net, Current (Note 1)
151 
Derivative liabilities
13 
37 
Total current liabilities
733 
1,328 
Deferred income taxes
465 
621 
Long-term Debt and Capital Lease Obligations
3,189 1
2,260 1
Derivative liabilities
Asset retirement obligations
99 
75 
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent
133 
151 
Other noncurrent liabilities
237 
28 
Contingent liabilities and commitments (Note 10)
   
   
Stockholders’ equity:
 
 
Preferred stock (100 million shares authorized at $0.01 par value; 7 million shares issued at December 31, 2015)
339 
Common stock (2 billion shares authorized at $0.01 par value; 275.4 million shares issued at December 31, 2015 and 203.7 million shares issued at December 31, 2014)
Additional paid-in-capital
6,164 
5,562 
Accumulated deficit
(2,971)
(1,244)
Accumulated other comprehensive income (loss)
(1)
Total stockholders’ equity
3,535 
4,319 
Noncontrolling interests in consolidated subsidiaries
109 
Total equity
3,535 
4,428 
Total liabilities and equity
$ 8,393 
$ 8,896 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 6 
$ 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
275,400,000 
203,700,000 
Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Product revenues:
 
 
 
Oil sales
$ 494 
$ 669 
$ 475 
Natural gas sales
138 
282 
259 
Natural gas liquid sales
23 
20 
10 
Total product revenues
655 
971 
744 
Gas management
286 
1,110 
882 
Net gain (loss) on derivatives not designated as hedges (Note 15)
418 
434 
(124)
Other
Total revenues
1,366 
2,523 
1,505 
Costs and expenses:
 
 
 
Lease and facility operating
145 
143 
109 
Gathering, processing and transportation
64 
71 
73 
Taxes other than income
62 
88 
68 
Gas management, including charges for unutilized pipeline capacity (Note 5)
261 
979 
927 
Exploration (Note 5)
85 
101 
417 
Depreciation, depletion and amortization
528 
363 
354 
Impairment of producing properties and costs of acquired unproved reserves
1
15 1
772 1
Net (gain) loss on sales of assets (Note 5)
(349)
General and administrative
210 
224 
218 
Acquisition costs (Note 2)
23 
Other—net
63 
13 
12 
Total costs and expenses
1,092 
1,997 
2,950 
Operating income (loss)
274 
526 
(1,445)
Interest expense (Note 2)
(187)
(123)
(108)
Loss on extinguishment of debt (Note 2)
(65)
Investment income, impairment of equity method investment and other
(2)
(19)
Income (loss) from continuing operations before income taxes
20 
404 
(1,572)
Provision (benefit) for income taxes
24 
148 
(567)
Income (loss) from continuing operations
(4)
256 
(1,005)
Income (loss) from discontinued operations
(1,722)
(85)
(186)
Net income (loss)
(1,726)
171 
(1,191)
Less: Net income (loss) attributable to noncontrolling interests
(6)
Net Income (Loss) Attributable to Parent
(1,727)
164 
(1,185)
Preferred Stock Dividends, Income Statement Impact
Net Income (Loss) Available to Common Stockholders,
(1,736)
164 
(1,185)
Income (Loss) from Continuing Operations Attributable to WPX
(13)
256 
(993)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX
$ (1,723)
$ (92)
$ (192)
Basic earnings (loss) per common share (Note 4):
 
 
 
Income (Loss) from Continuing Operations, Per Basic Share
$ (0.06)
$ 1.26 
$ (4.95)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share
$ (7.36)
$ (0.45)
$ (0.96)
Earnings Per Share, Basic
$ (7.42)
$ 0.81 
$ (5.91)
Basic weighted-average shares
234.2 
202.7 
200.5 
Diluted earnings (loss) per common share (Note 4)
 
 
 
Income (Loss) from Continuing Operations, Per Diluted Share
$ (0.06)
$ 1.24 
$ (4.95)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share
$ (7.36)
$ (0.44)
$ (0.96)
Earnings Per Share, Diluted
$ (7.42)
$ 0.80 
$ (5.91)
Diluted weighted-average shares
234.2 2
206.3 
200.5 2
Consolidated Statements of Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Condensed Statement of Income Captions [Line Items]
 
 
 
Net Income (Loss) Attributable to Parent
$ (1,727)
$ 164 
$ (1,185)
Preferred Stock Dividends, Income Statement Impact
Net Income (Loss) Available to Common Stockholders,
(1,736)
164 
(1,185)
Comprehensive income (loss) attributable to WPX Energy, Inc. common stockholders
(1,736)
164 
(1,188)
Other comprehensive income (loss):
 
 
 
Net reclassifications into earnings of net cash flow hedge gains, net of tax
1
1
(3)1
Other comprehensive income (loss), net of tax
$ 0 
$ 0 
$ (3)
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Statement of Partners' Capital [Abstract]
 
Income tax provision for cash flow hedge gains
$ 2 
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)
$ 5 
Consolidated Statements of Changes in Equity (USD $)
In Millions, unless otherwise specified
Total
Total Stockholders’ Equity
Preferred Stock [Member]
Common Stock
Capital in Excess of Par Value
Accumulated Deficit
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Balance at beginning of period at Dec. 31, 2012
$ 5,371 
$ 5,268 
 
$ 2 
$ 5,487 
$ (223)
$ 2 
$ 103 1
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss)
(1,191)
(1,185)
 
 
 
(1,185)
 
(6)1
Other comprehensive income (loss)
(3)
(3)
 
 
 
 
(3)
 
Comprehensive income (loss)
(1,194)
 
 
 
 
 
 
 
Contribution from noncontrolling interest
   
 
 
 
 
 
 
Contribution from noncontrolling interest1
 
 
 
 
 
 
 
Stock based compensation, net of tax benefit
29 
29 
 
 
29 
 
 
 
Balance at end of period at Dec. 31, 2013
4,210 
4,109 
 
5,516 
(1,408)
(1)
101 1
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss)
171 
164 
 
 
 
164 
 
1
Other comprehensive income (loss)
 
 
 
 
 
Comprehensive income (loss)
171 
 
 
 
 
 
 
 
Contribution from noncontrolling interest
 
 
 
 
 
 
1
Stock based compensation, net of tax benefit
46 
46 
 
 
46 
 
 
 
Balance at end of period at Dec. 31, 2014
4,428 
4,319 
 
5,562 
(1,244)
(1)
109 1
Noncontrolling Interest, Decrease from Deconsolidation
 
 
 
 
 
 
 
(110)
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss)
(1,726)
(1,727)
 
 
 
(1,727)
 
1
Other comprehensive income (loss)
 
 
 
 
 
 
 
Comprehensive income (loss)
(1,726)
 
 
 
 
 
 
 
Stock based compensation, net of tax benefit
26 
26 
 
 
26 
 
 
 
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings
(11)
(11)
 
 
(11)
 
 
 
Stock Issued During Period, Value, New Issues
292 
292 
 
 
292 
 
 
 
Stock Issued During Period, Value, Acquisitions
296 
296 
 
295 
 
 
 
Issuance of preferred stock to public, net of offering costs
339 
339 
339 
 
 
 
 
 
Stockholders' Equity, Other
(109)
 
 
 
 
 
Balance at end of period at Dec. 31, 2015
$ 3,535 
$ 3,535 
$ 339 
$ 3 
$ 6,164 
$ (2,971)
$ 0 
$ 0 1
Consolidated Statements of Changes in Equity (Parenthetical)
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Noncontrolling interest, ownership percentage by noncontrolling owners
31.00% 
31.00% 
31.00% 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Operating Activities
 
 
 
Net income (loss)
$ (1,726)
$ 171 
$ (1,191)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
940 
863 
940 
Deferred income tax provision (benefit)
(1,005)
46 
(645)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments
2,426 
236 
1,483 
Amortization of stock-based awards
35 
36 
32 
Loss on extinguishment of acquired debt and acquisition bridge financing fees
81 
Gain (loss) on sales of domestic assets and international interests
385 
(196)
41 
Cash provided (used) by operating assets and liabilities:
 
 
 
Accounts receivable
233 
51 
(43)
Inventories
(2)
19 
(5)
Margin deposits and customer margin deposits payable
26 
(10)
(18)
Other current assets
(7)
Accounts payable
(247)
41 
Accrued and other current liabilities
79 
(1)
(21)
Changes in current and noncurrent derivative assets and liabilities
199 
(559)
106 
Other, including changes in other noncurrent assets and liabilities
157 
10 
Net cash provided by operating activities(a)
811 1
1,070 1
636 1
Investing Activities
 
 
 
Capital expenditures
(1,124)2
(1,807)2
(1,154)2
Proceeds from sales of domestic assets and international interests
1,019 
374 
49 
Purchases of a business, net of cash acquired
(1,212)
Other
(4)
(6)
Net cash used in investing activities(a)
(1,316)1
(1,437)1
(1,111)1
Financing Activities
 
 
 
Proceeds from common stock
295 
16 
Proceeds from preferred stock
339 
Dividends paid on preferred stock
(6)
Proceeds from long-term debt
1,000 
500 
Payments for retirement of long-term debt
(45)
Payments for retirement of acquired debt
(1,055)
Borrowings on credit facility
841 
1,947 
970 
Payments on credit facility
(856)
(2,077)
(560)
Payments for debt issuance costs and acquisition bridge financing fees
(40)
(13)
Other
(29)
10 
Net cash provided by financing activities
473 
344 
426 
Net increase (decrease) in cash and cash equivalents
(32)
(23)
(49)
Effect of Exchange Rate on Cash and Cash Equivalents
(6)
(5)
Cash and cash equivalents at beginning of period
70 3
99 3
153 3
Cash and cash equivalents at end of period
$ 38 3
$ 70 3
$ 99 3
Consolidated Statements of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Statement of Cash Flows [Abstract]
 
 
 
Increase to properties and equipment
$ (865)
$ (1,934)
$ (1,207)
Changes in related accounts payable and accounts receivable
(259)
127 
53 
Capital expenditures
$ (1,124)1
$ (1,807)1
$ (1,154)1
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Notes)
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
Description of Business
Operations of our company include oil, natural gas and NGL development, production and gas management activities primarily located in Texas, North Dakota, New Mexico and Colorado in the United States. We specialize in development and production from tight-sands and shale formations in the 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 Piceance Basin in Colorado, which were sold April 8, 2016. We also had operations for a portion of 2015 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 the Piceance Basin, Powder River Basin and Apco are reported as discontinued operations.
The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company,” is at times referred to in the first person as “we,” “us” or “our.”
Basis of Presentation
These financial statements are prepared on a consolidated basis.
Our continuing operations are comprised of a single business segment, the domestic development, production and gas management activities of oil, natural gas and NGLs. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.
Discontinued operations
On February 8, 2016, we signed an agreement to sell our Piceance Basin operations to Terra Energy Partners LLC (“Terra”) for $910 million. This transaction closed on April 8, 2016. The assets and liabilities have been reclassified as held for sale on the Consolidated Balance Sheets and the results of operations of the Piceance Basin have been reclassified as discontinued operations on the Consolidated Statements of Operations (see Note 3).
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 10 for a discussion of contingencies related to Williams’ former power business (most of which was disposed of in 2007).
Recently Adopted Accounting Standards
In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. In August 2015, the FASB issued ASU 2015-15 to incorporate into the ASU an SEC announcement that the SEC staff will not object to an entity presenting the cost of securing a line of credit as an asset. The Company has adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of $31 million and $20 million of unamortized debt issuance costs related to the Company's senior unsecured notes from other noncurrent assets to long-term debt within its Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014, respectively. The unamortized costs associated with our revolving line of credit remain in other noncurrent assets for the periods presented. Other than this reclassification, the adoption of this standard did not have an impact on the Company's consolidated financial statements.
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 periods 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 early adopted this ASU in 2015.
In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes as part of the Simplification Initiative. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is effective for financial statements issued for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted as of the beginning of an interim or annual reporting period. The Company has adopted ASU 2015-17 prospectively beginning with the interim period October 1, 2015, thus prior periods were not retrospectively adjusted.
Accounting Standards Not Yet Adopted
In May 2014, the FASB issued ASU 2014-09 and has updated with additional ASUs, 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, as amended, 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 January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, enhancing the reporting model for financial instruments. The amendments in ASU 2016-01 address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is only permitted under specific circumstances. The Company is currently evaluating the impact, if any, of ASU 2016-01 to the Company's financial position, results of operations or cash flows.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the Company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions which impact these financials include:
impairment assessments of long-lived assets;
valuations of derivatives;
estimation of oil and natural gas reserves;
assessments of litigation-related contingencies;
asset retirement obligations; and
valuation of deferred tax assets.
 
These estimates are discussed further throughout these notes.
Cash and cash equivalents
Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash
Restricted cash consists of approximately $10 million and $6 million at December 31, 2015 and 2014, respectively, and is included in other current assets on the Consolidated Balance Sheets.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories
All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method. The following table presents a summary of inventories.
 
Years ended December 31,
 
2015
 
2014
 
(Millions)
Material, supplies and other
$
44

 
$
29

Crude oil production in transit
2

 
2

 
$
46

 
$
31


Properties and equipment
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves related to our discontinued operations and are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.
Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations.
Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization
Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
Impairment of long-lived assets
We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.
Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities
Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities
Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
 
Derivative Treatment
  
Accounting Method
 
Normal purchases and normal sales exception
  
Accrual accounting
 
Designated in a qualifying hedging relationship
  
Hedge accounting
 
All other derivatives
  
Mark-to-market accounting
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to gas management and for which we have not elected the normal purchases and normal sales exception;
realized gains and losses on all derivatives that settle financially;
realized gains and losses on derivatives held for trading purposes; and
realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product revenues
Revenues for sales of oil, natural gas and natural gas liquids are recognized when the product is sold and delivered. Revenues from production in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2015 and 2014 was insignificant. Additionally, natural gas revenues include $5 million in 2013 of realized gains from derivatives designated as cash flow hedges of our production sold.
Gas management revenues and expenses
Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Gas management activities include the managing of various natural gas related contracts such as transportation and related hedges. The Company also sells oil, natural gas and NGLs purchased from working interest owners in operated wells and other area third-party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
Charges for unutilized transportation capacity included in gas management expenses were $38 million, $57 million and $61 million in 2015, 2014 and 2013, respectively.
Capitalization of interest
We capitalize interest during construction on projects with construction periods of at least three months and a total estimated project cost in excess of $1 million. We use the weighted average rate of our outstanding debt (see Note 8).
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years.
Deferred tax liabilities and assets are classified as noncurrent in a classified statement of financial position. As of December 31, 2015, the Company adopted new guidance that seeks to simplify the presentation of deferred tax liabilities and assets and has applied its provisions prospectively thus prior periods were not retrospectively adjusted. See Note 9 for additional discussion.
Employee stock-based compensation
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 4).
Debt issuance costs
Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $45 million and $28 million as of December 31, 2015 and December 31, 2014, respectively. Approximately $31 million and $20 million of unamortized debt issuance costs related to the Company's senior unsecured notes and were reclassified from other noncurrent assets to long-term debt within our Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014, respectively. Debt issuance costs related to the senior unsecured Credit Facility remain recorded in other noncurrent assets on the Company's Consolidated Balance Sheets.
Acquisition (Notes)
Mergers, Acquisitions and Dispositions Disclosures [Text Block]
Acquisition
On August 17, 2015, we completed the acquisition of privately held RKI Exploration & Production, LLC (“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, 34 percent natural gas and 23 percent NGLs. As of December 31, 2014, RKI reported proved reserves in the Delaware Basin of 101.5 MMboe, 40 percent of which was oil, 35 percent natural gas and 25 percent NGLs.
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 8 and 13 for further discussion on the financing of this transaction.
The following table presents the unaudited pro forma financial results for the years ended December 31, 2015 and 2014 as if the Acquisition and related financings had been completed January 1, 2014. In addition, the year ended December 31, 2015 has 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.
 
 
Years Ended December 31,
 
 
2015
 
2014
 
 
(Millions)
Revenues
 
$
1,578

 
$
2,905

Net income (loss) from continuing operations attributable to WPX Energy, Inc.
 
$
81

 
$
278


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 used 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 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 the carryover 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 carryovers at the Acquisition date (see Note 9).
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, net of an estimated post-close settlement
 
$
1,251

Fair value of WPX common stock issued
 
296

Total consideration
 
$
1,547

Fair value of liabilities assumed:
 
 
Accounts payable
 
$
104

Accrued liabilities
 
74

Deferred income taxes
 
692

Long-term debt
 
990

Asset retirement obligation
 
23

Total liabilities assumed as of December 31, 2015
 
1,883

Fair value of assets acquired:
 
 
Cash and cash equivalents
 
51

Accounts receivable, net
 
80

Derivative assets, current
 
97

Derivative assets, noncurrent
 
34

Inventories
 
12

Other current assets
 
3

Properties and equipment(a)
 
3,149

Other noncurrent assets
 
4

Total assets acquired as of December 31, 2015
 
3,430

Net fair value of assets and liabilities
 
$
1,547

__________
(a) Properties and equipment reflect the following as of the Acquisition date:
Proved properties
 
$
881

Unproved properties
 
2,108

Gathering, processing and other facilities
 
157

Other
 
3

Total
 
$
3,149

Discontinued Operations
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]
Discontinued Operations
On February 8, 2016 we signed an agreement with Terra Energy Partners LLC (“Terra”) to sell WPX Energy Rocky Mountain, LLC that holds our Piceance Basin operations for $910 million. The agreement also requires Terra to become financially responsible for approximately $104 million in transportation obligations held by our marketing company. Additionally, in accordance with the sales agreement and prior to closing, WPX will novate a portion of WPX's natural gas derivatives with a fair value of $82 million as of December 31, 2015 to WPX Energy Rocky Mountain, LLC. The parties closed this sale in April of 2016. These operations are included in our domestic results presented below. We also have certain pipeline capacity obligations held by our marketing company with total commitments for 2016 and thereafter of approximately $423 million. We may record a portion of these obligations if they meet the definition of exit activities in association with exiting the Piceance Basin. See Note 16 for a discussion of an agreement signed in May 2016 related to a portion of the remaining transportation obligations.
The Piceance Basin represented 52 percent of our total proved reserves at December 31, 2015 and 58 percent of our total production for 2015.
Significant transactions for the Piceance Basin Operations reflected in the tables below are as follows:
As a result of market conditions including oil and natural gas prices in the fourth quarter of 2015, we performed impairment assessments of our proved producing properties. As a result of these assessments, which included the possibility of cash flows from a divestiture of the Piceance Basin, we recorded a total of $2,334 million in impairment charges associated with the Piceance Basin, of which approximately $2,308 million is recorded as a separate line on the table below and $26 million is included in exploration expenses.
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.
Impairments of exploratory well costs and dry hole costs for 2014 include $67 million of impairment related to our Niobrara Shale well costs in the Piceance Basin.
We recorded impairments in 2013, of $88 million in the Piceance Basin including impairments of capitalized costs of acquired unproved reserves of $19 million and $69 million in the third and fourth quarters, respectively, in the Kokopelli area.
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 pre-tax loss of $15 million related to this transaction during 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 with total commitments of $104 million through 2020 related to the Powder River properties sold. These commitments had been in excess of our production throughput. At the time of closing, we also had 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, which is included as a separate line below. This expense is the estimated present value of the $254 million in payments associated with these contracts remaining as of the Powder River Basin sales date, and includes the fair value of estimated recoveries from third parties and discounting based on our risk adjusted borrowing rate. Offsetting liabilities of $54 million and $133 million were recorded in accrued and other current liabilities and other noncurrent liabilities, respectively, as of the closing date.
The results of our Piceance Basin and Powder River Basin operations are included in our domestic results presented below.
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.
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.
Summarized Results of Discontinued Operations
For the year ended December 31, 2015
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
577

 
$
15

 
$
592

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
99

 
$
4

 
$
103

Gathering, processing and transportation
257

 

 
257

Taxes other than income
18

 
3

 
21

Accrual for contract obligations retained and related accretion
190

 

 
190

Gas management
1

 

 
1

Exploration
26

 

 
26

Depreciation, depletion and amortization
412

 

 
412

Impairment of assets held for sale
2,324

 

 
2,324

General and administrative
44

 
1

 
45

Other—net
(10
)
 

 
(10
)
Total costs and expenses
3,361

 
8

 
3,369

Operating income (loss)
(2,784
)
 
7

 
(2,777
)
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
(2,794
)
 
49

 
(2,745
)
Provision (benefit) for income taxes
(1,020
)
 
(3
)
 
(1,023
)
Income (loss) from discontinued operations
$
(1,774
)
 
$
52

 
$
(1,722
)

For the year ended December 31, 2014
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
1,159

 
$
163

 
$
1,322

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
142

 
$
37

 
$
179

Gathering, processing and transportation
327

 
1

 
328

Taxes other than income
54

 
28

 
82

Gas management, including charges for unutilized pipeline capacity
8

 

 
8

Exploration
72

 
4

 
76

Depreciation, depletion and amortization
458

 
42

 
500

Impairment of producing properties and costs of acquired unproved reserves
50

 

 
50

Loss on sale of working interest in the Piceance Basin
196

 

 
196

General and administrative
51

 
16

 
67

Other—net
(1
)
 
12

 
11

Total costs and expenses
1,357

 
140

 
1,497

Operating income (loss)
(198
)
 
23

 
(175
)
Interest capitalized
1

 

 
1

Investment income and other
6

 
19

 
25

Income (loss) from discontinued operations before income taxes
(191
)
 
42

 
(149
)
Provision (benefit) for income taxes(a)
(71
)
 
7

 
(64
)
Income (loss) from discontinued operations
$
(120
)
 
$
35

 
$
(85
)
__________
(a) International income tax provision for 2014 is net of $18 million deferred tax benefit for the excess tax basis in our investment in Apco's stock.

For the year ended December 31, 2013
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Total revenues
$
1,104

 
$
152

 
$
1,256

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
162

 
$
37

 
$
199

Gathering, processing and transportation
357

 
3

 
360

Taxes other than income
49

 
24

 
73

Gas management, including charges for unutilized pipeline capacity
4

 

 
4

Exploration
7

 
7

 
14

Depreciation, depletion and amortization
552

 
34

 
586

Impairment of producing properties and costs of acquired unproved reserves
280

 
3

 
283

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

 
(36
)
General and administrative
57

 
14

 
71

Other—net
5

 

 
5

Total costs and expenses
1,437

 
122

 
1,559

Operating income (loss)
(333
)
 
30

 
(303
)
Interest capitalized
4

 

 
4

Investment income and other
4

 
21

 
25

Income (loss) from discontinued operations before income taxes
(325
)
 
51

 
(274
)
Provision (benefit) for income taxes(a)
(119
)
 
31

 
(88
)
Income (loss) from discontinued operations
$
(206
)
 
$
20

 
$
(186
)

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

Assets and Liabilities in the Consolidated Balance Sheets Attributable to Discontinued Operations
As of December 31, 2015 the following table presents domestic assets classified as held for sale and liabilities associated with assets held for sale related to our Piceance Basin operations.
December 31, 2015
Total
 
 
Assets classified as held for sale
 
Current assets:
 
Accounts receivable (including an affiliate receivable)
$
55

Derivative assets
68

Inventories
13

Other
2

Total current assets
138

Properties and equipment, net(a)
880

Derivative assets
14

Total assets classified as held for sale—discontinued operations
$
1,032

Total assets classified as held for sale—continuing operations (Note 5)
40

Total assets classified as held for sale on the Consolidated Balance Sheets
$
1,072

 
 
Liabilities associated with assets held for sale
 
Current liabilities:
 
Accounts payable
$
93

Accrued and other current liabilities
47

Total current liabilities
140

Asset retirement obligations
133

Total liabilities associated with assets held for sale on the Consolidated Balance Sheets
$
273

__________
(a) Includes $2,308 million impairment in Piceance Basin of the net assets.

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 Piceance Basin, 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
140

 
25

 
165

Inventories
15

 
7

 
22

Other
3

 
14

 
17

Total current assets
158

 
75

 
233

Investments
18

 
134

 
152

Properties and equipment (successful efforts method of accounting)(a)
7,082

 
445

 
7,527

Less—accumulated depreciation, depletion and amortization
(3,513
)
 
(228
)
 
(3,741
)
Properties and equipment, net
3,569

 
217

 
3,786

Derivative assets
14

 

 
14

Other noncurrent assets
3

 
6

 
9

Total assets classified as held for sale—discontinued operations
$
3,762

 
$
432

 
$
4,194

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
$
3,962

 
$
432

 
$
4,394

 
 
 
 
 
 
Liabilities associated with assets held for sale
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
193

 
$
34

 
$
227

Accrued and other current liabilities
35

 
23

 
58

Total current liabilities
228

 
57

 
285

Deferred income taxes

 
13

 
13

Long-term debt

 
2

 
2

Asset retirement obligations
168

 
7

 
175

Other noncurrent liabilities
28

 
3

 
31

Total liabilities associated with assets held for sale—discontinued operations
$
424

 
$
82

 
$
506

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(b)
$
426

 
$
82

 
$
508

__________
(a) Domestic includes $45 million impairment in Powder River Basin of the net assets.
Noncontrolling interests in consolidated subsidiaries of $109 million as of December 31, 2014, related to assets classified as held for sale.
Cash Flows Attributable to Discontinued Operations
Excluding taxes and changes to working capital, total cash provided by operating activities related to domestic discontinued operations was $184 million, $585 million and $478 million for 2015, 2014 and 2013, respectively. Total cash used in investing activities related to domestic discontinued operations was $251 million, $512 million and $369 million for 2015, 2014 and 2013, respectively. Cash provided by operating activities related to our international operations was $3 million, $65 million and $56 million for 2015, 2014 and 2013, respectively. Total cash used in investing activities related our international operations was $15 million, $85 million and $43 million for 2015, 2014 and 2013, respectively.
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
 The following table summarizes the calculation of earnings per share.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc.
$
(4
)
 
$
256

 
$
(993
)
Less: Dividends on preferred stock
9

 

 

Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
$
(13
)
 
$
256

 
$
(993
)
Basic weighted-average shares
234.2

 
202.7

 
200.5

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

 
2.7

 

Stock options

 
0.9

 

Diluted weighted-average shares
234.2

 
206.3

 
200.5

Earnings (loss) per common share from continuing operations:
 
 
 
 
 
Basic
$
(0.06
)
 
$
1.26

 
$
(4.95
)
Diluted
$
(0.06
)
 
$
1.24

 
$
(4.95
)

 __________
(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.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Weighted-average nonvested restricted stock units and awards
1.3

 

 
2.5

Weighted-average stock options
0.1

 

 
1.1

Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 13)
15.5

 

 


The table below includes information related to stock options that were outstanding at December 31, 2015, 2014 and 2013 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
 
 
 
 
 
 
 
2015
 
2014
 
2013
Options excluded (millions)
2.6

 
1.4

 
0.4

Weighted-average exercise price of options excluded
$
16.16

 
$
18.42

 
$
20.24

Exercise price range of options excluded
$11.46 - $21.81

 
$16.46  - $21.81

 
$20.21  - $20.97

Fourth quarter weighted-average market price
$
7.43

 
$
15.96

 
$
19.97



For 2015, approximately 3.0 million nonvested restricted stock units and awards were antidilutive and were excluded from the computation of diluted weighted-average shares.
Asset Sales, Impairments and Exploration Expenses
Asset Sales, Impairments and Exploration Expenses
Asset Sales, Impairments, Other Expenses and Exploration Expenses
In 2014, we recorded a total of $15 million in impairment charges associated with exploratory well costs and producing properties recorded as a separate line on the Consolidated Statements of Operations. In 2013, we recorded a total of $1.1 billion in impairment charges of which $772 million is recorded as a separate line on the Consolidated Statements of Operations, $317 million is included in exploration expenses and $20 million is included in investment income, impairment of equity method investment and other. These impairments are discussed further in the sections below.
Asset Sales
In December 2015, we announced an agreement to sell our San Juan Basin gathering system for consideration of approximately $309 million to a portfolio company of ISQ Global Infrastructure Fund, a fund managed by I Squared Capital. The consideration reflects $285 million in cash, subject to closing adjustments, and a commitment estimated at $24 million in capital designated by the purchaser to expand the system to support WPX's development in the Gallup oil play. We are obligated to complete certain in-progress construction estimated to total approximately $13 million. Under the terms of the agreement, WPX will continue to operate, at the direction of the owner, the gathering system for an initial term of two years with the opportunity to continue in ensuing years. The parties expect to close in first-quarter 2016. Upon closing, the gathering system will consist of more than 220 miles of oil, gas and water gathering lines that WPX installed in conjunction with drilling in the Gallup oil play where it made a discovery in 2013. These assets totaled $40 million at December 31, 2015 and are classified as held for sale on the Consolidated Balance Sheets.
During the fourth quarter of 2015, we completed the sale of 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, at the direction of the owner, the system for a two year initial term and any renewal terms. The system 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. As a result of this transaction, we recorded a net gain of $70 million in fourth-quarter 2015. In addition, we accrued approximately $25 million related to future construction obligations under the terms of the agreement, of which $22 million is reported in other noncurrent liabilities and $3 million is reported in accrued and other current liabilities on the Consolidated Balance Sheet. We also accrued approximately $33 million of deferred gain related to these obligations, of which $29 million is reported in other noncurrent liabilities and $4 million is reported in accrued and other current liabilities on the Consolidated Balance Sheet.
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. The 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.
Impairments
The following table presents a summary of significant impairments of producing properties and costs of acquired
unproved reserves and impairment of equity method investments.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Impairment of producing properties and costs of acquired unproved reserves(a)
$

 
$
15

 
$
772

Impairment of equity method investment in Appalachian Basin
$

 
$

 
$
20


 __________
(a)
Excludes related impairments of unproved leasehold included in exploration expenses.
As a result of declines in forward crude oil and natural gas prices primarily during the fourth-quarter 2014 as compared to forward prices as of December 31, 2013, we performed impairment assessments of our proved producing properties and costs of acquired unproved reserves. Accordingly, we recorded the following impairments during 2014:
$11 million impairment in the fourth quarter in the Green River Basin; and
$4 million of impairments in the fourth quarter of other properties.
As a result of declines in forward natural gas prices primarily during the fourth-quarter 2013 as compared to forward prices as of December 31, 2012, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves. Accordingly, we recorded a $772 million impairment in the fourth quarter of 2013 of proved producing oil and gas properties in the Appalachian Basin.
The nature of the assets in the equity method investment in the Appalachian Basin is such that under normal circumstances an entity would capitalize and evaluate the assets as part of its producing properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing properties that utilize the assets of the entity. As a result of the 2013 impairment of the producing properties in the Appalachian Basin, we recorded an impairment of the equity method investment in 2013.
Our impairment analyses included an assessment of undiscounted and discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (see Note 14).
Other Expenses
In December 2015, we plugged and abandoned the remaining wells serviced by a certain natural gas gathering system in the Appalachian Basin. As a result, we recorded approximately $23 million associated with the net present value of future obligations under the gathering agreement which is included in other-net on the Consolidated Statement of Operations.
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.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Geologic and geophysical costs
$
7

 
$
6

 
$
12

Impairments of exploratory area well costs and dry hole costs
24

 
21

 
3

Unproved leasehold property impairments, amortization and expiration
54

 
74

 
402

Total exploration expenses
$
85

 
$
101

 
$
417


Impairments of exploratory well costs and dry hole costs for 2015 include $24 million related to a non-core exploratory play where we no longer intend to continue exploration activities. Impairments of exploratory well costs and dry hole costs for 2014 include $16 million of impairments in other exploratory areas where management has determined to cease exploratory activities. The remaining amount in 2014 represents dry hole costs associated with exploratory wells where hydrocarbons were not detected.
Unproved leasehold property impairments, amortization and expiration in 2015 includes impairments of $26 million related to a non-core exploratory play where we no longer intend to continue exploration activities. Unproved leasehold property impairment, amortization and expiration in 2014 includes $41 million related to unproved leasehold costs in exploratory areas where we no longer intend to continue exploration activities. Unproved leasehold impairment, amortization and expiration in 2013 includes a $317 million impairment to estimated fair values of Appalachia leasehold associated with our impairment of the producing properties in the Appalachian Basin.
Properties and Equipment
Properties and Equipment
Properties and Equipment
Properties and equipment is carried at cost and consists of the following:
 
 
Estimated
Useful
Life(a)
(Years)
 
December 31,
 
2015
 
2014
 
 
 
(Millions)
Proved properties
(b)
 
$
5,520

 
$
3,852

Unproved properties
(c)
 
2,342

 
349

Gathering, processing and other facilities
15-25
 
217

 
102

Construction in progress
(c)
 
198

 
368

Other
3-40
 
138

 
131

Total properties and equipment, at cost
 
 
8,415

 
4,802

Accumulated depreciation, depletion and amortization
 
 
(1,893
)
 
(1,407
)
Properties and equipment—net
 
 
$
6,522

 
$
3,395

__________
(a)
Estimated useful lives are presented as of December 31, 2015.
(b)
Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
(c)
Unproved properties and construction in progress are not yet subject to depreciation and depletion.
On August 17, 2015 we completed the Acquisition of RKI. See Note 2 for additional detail related to the Acquisition.
During 2014, we purchased oil and natural gas properties in the San Juan Basin for $150 million. The properties purchased included both producing wells and undeveloped locations. Approximately $50 million of the purchase price was allocated to proved producing properties and the remainder to proved undeveloped or unproved leasehold within properties and equipment. The purchase is included within our capital expenditures on the Consolidated Statements of Cash Flows. 
Unproved properties consist primarily of non-producing leasehold in the Permian, San Juan and Williston Basins.
Asset Retirement Obligations 
Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.
A rollforward of our asset retirement obligations for the years ended 2015 and 2014 is presented below.
 
 
2015
 
2014
 
(Millions)
Balance, January 1
$
77

 
$
67

Liabilities incurred
26

 
9

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

 

Estimate revisions
(4
)
 
(3
)
Accretion expense(a)
5

 
5

Balance, December 31
$
102

 
$
77

Amount reflected as current
$
3

 
$
2

__________
(a)
Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
Estimate revisions in 2014 are primarily associated with decreases in anticipated plug and abandonment costs.
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable
The following table presents a summary of our accounts payable as of the dates indicated below.
 
December 31,
 
2015
 
2014
 
(Millions)
Trade
$
85

 
$
171

Accrual for capital expenditures
65

 
235

Royalties
71

 
71

Affiliate payable for revenue related to assets held for sale
43

 
118

Other
14

 
43

 
$
278

 
$
638


Accrued and other current liabilities
The following table presents a summary of our accrued and other current liabilities as of the dates indicated below.
 
December 31,
 
2015
 
2014
 
(Millions)
Taxes other than income taxes
$
25

 
$
10

Accrued interest
82

 
53

Compensation and benefit related accruals
61

 
55

Gathering and transportation
8

 
7

Gathering and transportation related to exited areas
56

 
6

Accrued income taxes
41

 
3

Other, including other loss contingencies
29

 
11

 
$
302

 
$
145

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.
 
December 31,
 
2015 (a)
 
2014 (a)
 
(Millions)
5.250% Senior Notes due 2017
$
355

 
$
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
265

 
280

Other
1

 
1

Total debt
$
3,221

 
$
2,281

Less: Current portion of long-term debt
1

 
1

Total long-term debt
$
3,220

 
$
2,280

Less: Debt issuance costs
$
31

 
$
20

Total long-term debt, net(b)
$
3,189

 
$
2,260

__________
(a)
Interest paid on debt totaled $120 million and $97 million for 2015 and 2014, respectively.
(b)
Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
Subsequent to December 31, 2015, we have borrowed an additional $110 million on our revolving credit facility. Also subsequent to December 31, 2015 and through February 25, 2016, we have repurchased $51 million of long-term notes due in 2017. See Note 16 for information regarding 2016 amendments to and amounts outstanding under our Credit Facility and the tendering of the outstanding Senior Notes due in 2017 subsequent to February 25, 2016.

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. 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. 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 net proceeds from the offering of the 2020 and 2023 Notes was approximately $494 million for each note after deducting the initial purchasers’ discounts and our offering expenses. The proceeds were used to repay borrowings under our Credit Facility.
In September 2014, we issued $500 million aggregate principal amount of 5.250% Senior Notes due 2024 (“the 2024 Notes”) pursuant to our automatic shelf registration statement on Form S-3 filed with the Securities and Exchange Commission. The 2024 Notes were issued under an indenture, as supplemented by a supplemental indenture, each between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the 2024 Notes were approximately $494 million after deducting the initial purchasers’ discounts and our offering expenses. The proceeds were used to repay borrowings under our Credit Facility.
In November 2011, we issued $400 million aggregate principal amount of 5.250% Senior Notes due 2017 (the “2017 Notes”) and $1.1 billion aggregate principal amount of 6.000% Senior Notes due 2022 (the “2022 Notes”) pursuant to a private offering, and in June 2012 we exchanged these notes for registered 2017 Notes and 2022 Notes. The 2017 Notes and 2022 Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee.
The terms of the indentures governing our notes are substantially identical.
Optional Redemption. We have the option prior to maturity for the 2017 Notes, prior to July 1, 2020 for the 2020 Notes, prior to October 15, 2021 for the 2022 Notes, prior to June 1, 2023 for the 2023 Notes and prior to June 15, 2024 for the 2024 Notes to redeem some or all of such notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. We also have the option at any time or from time to time on or after July 1, 2020 to redeem the 2020 Notes, or on or after October 15, 2021 to redeem the 2022 Notes, or on or after June 1, 2023 to redeem the 2023 Notes and or on or after June 15, 2024, to redeem the 2024 Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture.
During 2015, we repurchased approximately $45 million of the 2017 Notes. The Company's next debt maturity does not occur until 2020.
Change of Control. If we experience a change of control (as defined in the indentures governing the notes) accompanied by a specified rating decline, we must offer to repurchase the notes of such series at 101% of their principal amount, plus accrued and unpaid interest.
Covenants. The terms of the indentures governing our notes restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indentures also require us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indentures. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The indentures do not require the maintenance of any financial ratios or specified levels of net worth or liquidity.
Events of Default. Each of the following is an “Event of Default” under the indentures with respect to the notes of any series:
(1) a default in the payment of interest on the notes when due that continues for 30 days;
(2) a default in the payment of the principal of or any premium, if any, on the notes when due at their stated maturity,
upon redemption, or otherwise;
(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in
clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting
covenant under the indenture, which failure continues for a period of 90 days, after the date on which written notice of
such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within
such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be
automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using
commercially reasonable efforts to cure such failure; and
(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.
Credit Facility Agreement
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. As of December 31, 2015, the weighted average variable interest rate was 2.20% on the $265 million outstanding under the Credit Facility Agreement.
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 December 31, 2015, our credit rating with S&P was BB, positive outlook and our credit rating with Moody's is Ba1, negative outlook. Subsequent to December 31, 2015, our credit ratings were downgraded to BB-, negative outlook and B2, negative outlook with S&P and Moody's, respectively.
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. Furthermore, the ratio of Consolidated Indebtedness to Consolidated Total Capitalization is not permitted to be greater than 60 percent and the Company may not permit the ratio of Consolidated EBITDAX to Consolidated Interest Charges to be less than 2.5 to 1.00 for the life of the agreement.
As of December 31, 2015, we were in compliance with our financial covenants and had full access to the Credit Facility.
Interest on borrowings under the Credit Facility Agreement are payable at rates per annum equal to, at our option: (1) a fluctuating base rate equal to the Alternate Base Rate plus the Applicable Rate, or (2) a periodic fixed rate equal to LIBOR plus the Applicable Rate. The Alternate Base Rate will be the highest of (i) the federal funds rate plus 0.5%, (ii) The Wells Fargo Bank, National Association, publicly announced prime rate, and (iii) one-month LIBOR plus 1.0%. The Applicable Rate is defined in the Credit Facility Agreement and is determined by which interest rate we select and the ratings of our long-term unsecured debt. At December 31, 2015, the Applicable Rate was 1.875% on our LIBOR loans and 0.875% on our alternate base rate loans. Additionally, we will be required to pay a commitment fee, based on the ratings of our long-term unsecured debt, on the unused portion of the commitments under the Credit Facility Agreement. At December 31, 2015, the commitment fee rate was 0.30%.
The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of our subsidiaries to incur indebtedness; our and our subsidiaries' ability to grant certain liens, materially change the nature of our or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of our material subsidiaries to enter into certain restrictive agreements; our and our material subsidiaries' ability to enter into certain affiliate transactions; and our ability to merge or consolidate with any person or sell all or substantially all of our assets to any person. We and our subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to certain exceptions and/or standards of materiality applicable to the contracting parties that differ from those applicable to investors.
The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to us occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of any loans outstanding under the Credit Facility Agreement at the time, in addition to the exercise of other rights and remedies available.
Letters of Credit
WPX has also entered into three bilateral, uncommitted letter of credit (“LC”) agreements most of which expire throughout 2016. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At December 31, 2015, a total of $233 million in letters of credit have been issued, a majority of which support interstate pipeline contracts. If these letter of credit agreements are not renewed, we may issue letters of credit under our Credit Facility.
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
The following table includes the provision (benefit) for income taxes from continuing operations.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Provision (benefit):
 
 
 
 
 
Current:
 
 
 
 
 
Federal
$
(4
)
 
$
8

 
$
(28
)
State
7

 
1

 
(5
)
 
3

 
9

 
(33
)
Deferred:
 
 
 
 
 
Federal
12

 
134

 
(496
)
State
9

 
5

 
(38
)
 
21

 
139

 
(534
)
Total provision (benefit)
$
24

 
$
148

 
$
(567
)

 
The following table provides reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Provision (benefit) at statutory rate
$
7

 
$
141

 
$
(550
)
Increases (decreases) in taxes resulting from:
 
 
 
 
 
State income taxes (net of federal benefit)
4

 
4

 
(25
)
State income tax legislation change (net of federal benefit)

 
9

 

Effective state income tax rate change (net of federal benefit)
7

 
(9
)
 
(3
)
Other
6

 
3

 
11

Provision (benefit) for income taxes
$
24

 
$
148

 
$
(567
)

The following table includes significant components of deferred tax liabilities and deferred tax assets.
 
December 31,
 
2015
 
2014
 
(Millions)
Deferred tax liabilities:
 
 
 
Properties and equipment
$
988

 
$
738

Derivatives, net
155

 
170

Other, net
1

 
17

Total deferred tax liabilities
1,144

 
925

Deferred tax assets:
 
 
 
Accrued liabilities and other
248

 
124

Alternative minimum tax credits
114

 
60

Loss carryovers
441

 
51

Other, net

 
32

Total deferred tax assets
803

 
267

Less: valuation allowance
124

 
114

Total net deferred tax assets
679

 
153

Net deferred tax liabilities
$
465

 
$
772


Net cash payments (refunds) for income taxes were $(8) million, $9 million and $(26) million in 2015, 2014 and 2013, respectively.
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 the Apco sale resulted in a $42 million capital loss for which a valuation allowance was established in 2014.
Significant changes to our operations during 2015 resulted in changes to our anticipated future state apportionment for our estimated state deferred tax liability. As a result of these changes and the differing state tax rates, we accrued an additional $7 million of deferred tax expense in 2015. Tax reform legislation that was enacted by the state of New York on March, 31, 2014 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. However, due to announced asset sales in fourth-quarter 2014, our state effective tax rate decreased resulting in a $9 million deferred tax benefit.
The acquisition of the stock of RKI in third-quarter 2015 (see Note 2) resulted in an increase to our deferred tax liabilities of $693 million as of the Acquisition date. Included in this amount are deferred tax assets for federal net operating loss (“NOL”) carryovers of $125 million, minimum tax credits of $50 million and state NOL carryovers of $7 million.
The Company has federal NOL carryovers of approximately $902 million at December 31, 2015, including the RKI NOL, that will not begin to expire until 2032. In addition, we have $47 million of capital loss carryovers at December 31, 2015, that will begin to expire in 2020.
The Company has state NOL carryovers, including the RKI carryovers, of approximately $2.0 billion and $875 million at 2015 and 2014, respectively, of which more than 98 percent expire after 2029.
The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax is subject to various limitations under the Internal Revenue Code (the Code). The utilization of such carryovers may be limited upon the occurrence of certain ownership changes during any three-year period resulting in an aggregate change of more than 50 percent in beneficial ownership (an Ownership Change). As of December 31, 2015, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for RKI effective with the Acquisition. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the Acquisition.
We have recorded valuation allowances against deferred tax assets attributable primarily to certain state NOL carryovers as well as our federal capital loss carryover. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we also consider future taxable income exclusive of reversing temporary differences and carryovers, and tax-planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets. Valuation allowances that we have recorded are due to our expectation that we will not have sufficient income, or income of a sufficient character, in those jurisdictions to which the associated deferred tax asset applies.
In previous periods, our deferred income tax liabilities and assets have been separated into current and noncurrent amounts. The company adopted ASU No. 2015-17: Balance Sheet Classification of Deferred Taxes as of December 31, 2015. See Note 1 for further discussion.
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.
The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.
As of December 31, 2015, the Company has no significant unrecognized tax benefits. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of an unrecognized tax benefit.
Contingent Liabilities and Commitments
Contingent Liabilities and Commitments
Contingent Liabilities and Commitments
Royalty litigation
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs’ proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We have completed the accounting process under the standard and have obtained the court's approval. However, as we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law, we have appealed this matter to the Colorado Court of Appeals. Plaintiffs have now filed a second class action lawsuit in the District Court, Garfield County containing similar allegations but related to subsequent time periods. The parties have agreed to 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 where the court denied plaintiffs' motion for class certification. 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 January 2009 through December 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.
Matters 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 December 31, 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 December 31, 2015 and December 31, 2014, the Company had accrued approximately $17 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.
Commitments
As part of managing our commodity price risk, we utilize contracted pipeline capacity to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2015 are as follows:
 
 
(Millions)
2016
$
140

2017
130

2018
116

2019
104

2020
91

Thereafter
105

 
 

Total
$
686


In conjunction with our exit of the Powder River Basin, we recorded liabilities associated with certain pipeline capacity obligations held by our marketing company of which $29 million and $84 million is recorded in accrued and other current liabilities and other noncurrent liabilities, respectively, as of December 31, 2015. Commitments related to these pipeline agreements for 2016 and beyond total $139 million and are included in the table above. Also included in the table is approximately $527 million of transportation obligations primarily associated with our Piceance Basin of which $104 million will become the financial responsibility of the purchaser (see Note 3 of Notes to Consolidated Financial Statements). See Note 16 for a discussion of an agreement signed in May 2016 related to a portion of the remaining transportation obligations.
We have certain commitments, for natural gas gathering and treating services, which total $524 million, including approximately $106 million associated with our Piceance Basin operations that will be assumed by the purchaser, $92 million associated with our exit from the Powder River Basin and $33 million associated with gathering commitments in a portion of our Appalachian Basin operations (see Notes 3 and 5 of the Notes to Consolidated Financial Statements). Liabilities associated with the Powder River Basin of $19 million and $40 million were recorded in accrued and other current liabilities and other noncurrent liabilities, respectively, as of December 31, 2015. In addition, we accrued approximately $23 million related to the abandonment of a portion of our Appalachian Basin operations, of which $20 million is recorded in other noncurrent liabilities as of December 31, 2015. Commitments other than those associated with our Piceance Basin operations will be settled over approximately eight years.
Future minimum annual rentals under noncancelable operating leases as of December 31, 2015, are payable as follows:
 
(Millions)
2016
$
28

2017
23

2018
12

2019
7

2020
7

Thereafter
9

 
 
Total
$
86


Total rent expense, excluding amounts capitalized, was $28 million, $26 million and $23 million in 2015, 2014 and 2013, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.
Employee Benefit Plans
Employee Benefit Plans
Employee Benefit Plans
WPX has a defined contribution plan which matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution of equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $15 million, $17 million and $16 million for 2015, 2014 and 2013, respectively. Approximately $9 million and $10 million were included in accrued and other current liabilities at December 31, 2015 and December 31, 2014, respectively, related to the non-matching annual employer contribution.
Stock-Based Compensation
Stock-Based Compensation
Stock-Based Compensation
WPX Energy, Inc. 2013 Incentive Plan
We have an equity incentive plan (“2013 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2013 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. The number of shares of common stock authorized for issuance pursuant to all awards granted under the 2013 Incentive Plan is 19.6 million shares. The 2013 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2013 Incentive Plan.
The ESPP allows domestic employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. The first offering under the ESPP commenced on March 1, 2012 and ended on June 30, 2012. Subsequent offering periods are from January through June and from July through December. Employees purchased 191 thousand shares at an average price of $7.05 per share during 2015.
Employee stock-based awards
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.
Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at fair value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Total stock-based compensation expense for the years ended December 31, 2015, 2014 and 2013 was $35 million, $35 million and $31 million, respectively. Stock-based compensation expense is reflected in general and administrative expense; however, approximately $4 million, $5 million and $4 million for the years ended December 31, 2015, 2014 and 2013, respectively, is included in discontinued operations. Measured but unrecognized stock-based compensation expense at December 31, 2015 was $37 million. This amount is comprised of $1 million related to stock options and $36 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2015.
  
WPX Plan
Stock Options
Options
 
Weighted-
Average
Exercise
Price
 
Aggregate
Intrinsic
Value
 
(Millions)
 
 
 
(Millions)
Outstanding at December 31, 2014(a)
3.1

 
$
14.80

 
$
2

Granted

 
$

 
 
Exercised
(0.2
)
 
$
10.33