WPX ENERGY, INC., 10-Q filed on 8/2/2018
Quarterly Report
v3.10.0.1
Document and Entity Information - shares
6 Months Ended
Jun. 30, 2018
Aug. 01, 2018
Document Documentand Entity Information [Abstract]    
Document Type 10-Q  
Amendment Flag false  
Document Period End Date Jun. 30, 2018  
Document Fiscal Year Focus 2018  
Document Fiscal Period Focus Q2  
Trading Symbol WPX  
Entity Registrant Name WPX ENERGY, INC.  
Entity Central Index Key 0001518832  
Current Fiscal Year End Date --12-31  
Entity Filer Category Large Accelerated Filer  
Entity Common Stock, Shares Outstanding   420,013,829
v3.10.0.1
Consolidated Balance Sheet (Unaudited) - USD ($)
$ in Millions
Jun. 30, 2018
Dec. 31, 2017
Current assets:    
Cash and Cash Equivalents, at Carrying Value $ 103 $ 189
Accounts receivable, net of allowance of $2 million as of June 30, 2018 and December 31, 2017 323 307
Derivative assets, current 136 36
Inventories 40 30
Assets classified as held for sale (Note 2) 0 811
Other 26 28
Total current assets 628 1,401
Long-term Investments 92 70
Properties and equipment (successful efforts method of accounting) 9,314 8,674
Less—accumulated depreciation, depletion and amortization (2,340) (1,983)
Properties and equipment, net 6,974 6,691
Derivative assets, noncurrent 49 23
Other noncurrent assets 27 22
Total assets 7,770 8,207
Current liabilities:    
Accounts payable 563 446
Accrued and other current liabilities 148 209
Liabilities associated with assets held for sale (Note 2) 0 20
Derivative liabilities, current 363 171
Total current liabilities 1,074 846
Deferred income taxes 42 117
Long-term debt, net [1] 2,154 2,575
Derivative liabilities, noncurrent 89 65
Asset retirement obligations 48 32
Other noncurrent liabilities 428 445
Stockholders’ equity:    
Preferred stock (100 million shares authorized at $0.01 par value; 4.8 million shares outstanding at June 30, 2018 and December 31, 2017) 232 232
Common stock (2 billion shares authorized at $0.01 par value; 400.3 million and 398.3 million shares issued and outstanding at June 30, 2018 and December 31, 2017) 4 4
Additional paid-in-capital 7,483 7,479
Accumulated deficit (3,784) (3,588)
Total stockholders’ equity 3,935 4,127
Total liabilities and equity $ 7,770 $ 8,207
[1] Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
v3.10.0.1
Consolidated Balance Sheet (Unaudited) (Parenthetical) - USD ($)
$ in Millions
Jun. 30, 2018
Dec. 31, 2017
Statement of Financial Position [Abstract]    
Allowance for doubtful accounts $ 2 $ 2
Preferred stock, par value $ 0.01 $ 0.01
Preferred stock, shares authorized 100,000,000 100,000,000
Preferred stock, shares outstanding 4,800,000 4,800,000
Common stock, par value $ 0.01 $ 0.01
Common stock, shares authorized 2,000,000,000 2,000,000,000
Common stock, shares issued and outstanding 400,300,000 398,300,000
v3.10.0.1
Consolidated Statement of Operations (Unaudited) - USD ($)
shares in Millions, $ in Millions
3 Months Ended 6 Months Ended
Jun. 30, 2018
Jun. 30, 2017
Jun. 30, 2018
Jun. 30, 2017
Product revenues:        
Oil sales $ 468 $ 194 $ 828 $ 353
Natural gas sales 16 16 33 33
Natural gas liquid sales 36 16 66 27
Total product revenues 520 226 927 413
Net gain (loss) on derivatives (154) 116 (223) 319
Commodity management 64 8 100 13
Total revenues 430 350 804 745
Costs and expenses:        
Depreciation, depletion and amortization 197 141 358 254
Lease and facility operating 59 41 114 77
Gathering, processing and transportation 20 6 38 11
Taxes other than income 41 19 71 32
Exploration (Note 4) 17 16 36 52
General and administrative (including equity-based compensation of $10 million, $8 million, $17 million and $15 million for the respective periods) 44 44 87 85
Commodity management 54 8 93 13
Net gain on sales of assets (Note 4) (1) (7) 0 (38)
Other—net 2 7 4 11
Total costs and expenses 433 275 801 497
Operating income (loss) (3) 75 3 248
Interest expense (39) (46) (85) (93)
Gain (Loss) on Extinguishment of Debt (71) 0 (71) 0
Investment income (loss) and other 1 0 0 2
Income (loss) from continuing operations before income taxes (112) 29 (153) 157
Benefit for income taxes (33) (298) (48) (265)
Income (loss) from continuing operations (79) 327 (105) 422
Loss from discontinued operations (2) (251) (91) (254)
Net income (loss) (81) 76 (196) 168
Preferred Stock Dividends, Income Statement Impact 4 4 8 8
Net income (loss) available to WPX Energy, Inc. common stockholders (85) 72 (204) 160
Amounts available to WPX Energy, Inc. common stockholders:        
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share (83) 323 (113) 414
Loss from discontinued operations $ (2) $ (251) $ (91) $ (254)
Income (Loss) from Continuing Operations, Per Basic Share $ (0.21) $ 0.81 $ (0.28) $ 1.06
Discontinued Operation, Income (Loss) from Discontinued Operation, Per Basic Share 0.00 (0.63) (0.23) (0.65)
Earnings Per Share, Basic $ (0.21) $ 0.18 $ (0.51) $ 0.41
Weighted Average Number of Shares Outstanding, Basic 400.0 397.8 399.3 392.1
Income (Loss) from Continuing Operations, Per Diluted Share $ (0.21) $ 0.77 $ (0.28) $ 1.01
Discontinued Operation, Income (Loss) from Discontinued Operation, Per Diluted Share 0.00 (0.60) (0.23) (0.61)
Earnings Per Share, Diluted $ (0.21) $ 0.17 $ (0.51) $ 0.40
Weighted Average Number of Shares Outstanding, Diluted 400.0 [1] 423.2 [1] 399.3 [1] 418.8
[1] The following table includes amounts that have been excluded from the computation of diluted earnings (loss) 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. The excluded amounts are as follows: Three monthsended June 30, Six monthsended June 30, 2018 2018 (Millions)Weighted-average nonvested restricted stock units and awards2.9 3.0Weighted-average stock options0.2 0.2Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock19.8 19.8
v3.10.0.1
Consolidated Statement of Operations (parenthetical) - USD ($)
$ in Millions
3 Months Ended 6 Months Ended
Jun. 30, 2018
Jun. 30, 2017
Jun. 30, 2018
Jun. 30, 2017
Non-cash equity-based compensation expense $ 10 $ 8 $ 17 $ 15
v3.10.0.1
Consolidated Statement of Changes in Equity (Unaudited) - 6 months ended Jun. 30, 2018 - USD ($)
$ in Millions
Total
Preferred Stock
Common Stock
Additional Paid-In- Capital
Accumulated Deficit
December 31, 2017 at Dec. 31, 2017 $ 4,127 $ 232 $ 4 $ 7,479 $ (3,588)
Increase (Decrease) in Stockholders' Equity [Roll Forward]          
Net income (loss) (196)       (196)
Stock-based compensation, net of tax impact 12     12  
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings (8)     (8)  
June 30, 2018 at Jun. 30, 2018 $ 3,935 $ 232 $ 4 $ 7,483 $ (3,784)
v3.10.0.1
Consolidated Statements of Cash Flows - USD ($)
$ in Millions
6 Months Ended
Jun. 30, 2018
Jun. 30, 2017
Operating Activities(a)    
Net income (loss) $ (196) $ 168
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation Depletion And Amortization Including Discontinued Portion 365 318
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations (75) (24)
Provision For Impairment Of Properties And Equipment Including Certain Exploration Expenses And Equity Method Investment 37 58
Net (gain) loss on derivatives 223 (319)
Net settlements related to derivatives 133 (9)
Amortization of stock-based awards 18 17
Gain (Loss) on Extinguishment of Debt (71) 0
Net (gain) loss on sales of assets including discontinued operations 151 (41)
Cash provided (used) by operating assets and liabilities:    
Accounts receivable (16) (49)
Inventories (11) (3)
Other current assets 4 (5)
Accounts payable 73 72
Federal income taxes receivable 0 12
Accrued and other current liabilities (59) (45)
Liabilities accrued in prior years for retained transportation and gathering contracts related to discontinued operations (28) (29)
Other, including changes in other noncurrent assets and liabilities 4 3
Net cash provided by operating activities(a) [1] 428 142
Investing Activities(a)    
Capital Expenditures [2] (660) (542)
Proceeds from sales of assets 686 38
Purchase of a business 0 (798)
Purchase of investments (23) (3)
Net cash provided by (used in) investing activities(a) [1] 3 (1,305)
Financing Activities    
Proceeds from common stock 5 671
Dividends paid on preferred stock (8) (7)
Borrowings on credit facility 303 85
Payments on credit facility (303) (60)
Proceeds from long-term debt, net of discount 494 0
Payments for retirement of long-term debt, including premium 986 0
Taxes paid for shares withheld (12) (10)
Payments for debt issuance costs and credit facility amendment fees 10 0
Proceeds from (Payments for) Other Financing Activities 1 (1)
Net cash provided by (used in) financing activities (516) 678
Net decrease in cash and cash equivalents and restricted cash (85) (485)
Cash, cash equivalents and restricted cash at beginning of period 201 506
Cash and cash equivalents and restricted cash at end of period 116 21
Increase to properties and equipment (705) (596)
Changes In Related Accounts Payable $ 45 $ 54
[1] Amounts reflect continuing and discontinued operations unless otherwise noted. See Note 2 of Notes to Consolidated Financial Statements for discussion of discontinued operations.
[2] (b) Increase to properties and equipment(705) (596)Changes in related accounts payable and accounts receivable45 54Capital expenditures(660) (542)
v3.10.0.1
Basis of Presentation and Description of Business
6 Months Ended
Jun. 30, 2018
Accounting Policies [Abstract]  
Basis of Presentation and Description of Business
Description of Business and Basis of Presentation
Description of Business
Operations of our company include oil, natural gas and NGL development and production primarily located in Texas, New Mexico and North Dakota. We specialize in development and production from tight-sands and shale formations in the Delaware and Williston Basins. Associated with our commodity production are sales and marketing activities, referred to as commodity management activities, that include oil and natural gas purchased from third-party working interest owners in operated wells and the management of various commodity related contracts such as transportation.
In March 2018, we sold our properties in the San Juan Basin’s Gallup oil play (“San Juan Gallup”) and in December 2017, we sold our natural gas-producing properties in the San Juan Basin (“San Juan Legacy”). Collectively, the San Juan Gallup and San Juan Legacy comprised our San Juan Basin operations. Subsequent to the closing of these transactions, we no longer have operations in the San Juan Basin. As a result of these divestments, the results of operations of the San Juan Basin are classified as discontinued operations on the Consolidated Statements of Operations. See Note 2 for additional information on these transactions.
In addition, we have sold other operations which are reported as discontinued operations and are discussed in Note 2 of Notes to Consolidated Financial Statements.
The consolidated businesses represented herein as WPX Energy, Inc. is also referred to as “WPX,” the “Company,” “we,” “us” or “our.”
Basis of Presentation
The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2017 in Exhibit 99.1 of our Form 8-K filed on May 7, 2018. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at June 30, 2018, results of operations for the three and six months ended June 30, 2018 and 2017, changes in equity for the six months ended June 30, 2018 and cash flows for the six months ended June 30, 2018 and 2017. The Company has no elements of comprehensive income (loss) other than net income (loss).
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States.
Discontinued Operations
See Note 2 for a discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
Recently Adopted Accounting Standards
The Company adopted Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, effective January 1, 2018 using the modified retrospective method. The core principle of the guidance in ASU 2014-09 is 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. The adoption of ASU 2014-09 was not material to our revenues or operating income (loss) or to our consolidated balance sheet because our performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of our contracts will continue to be recognized as control of products is transferred to the customer. A majority of the Company’s sales contracts at June 30, 2018 have terms of less than one year. For such contracts, we have used the practical expedient in ASC 606-10-50-14 which exempts an entity from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. For sales contracts with terms greater than one year, we have utilized the practical expedient in ASC 606-10-50-14A, which provides that an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts for all products, each unit of production represents a separate performance obligation that is satisfied upon delivery of product to the customer, thus, future volumes to be delivered are wholly unsatisfied at the reporting period end. We incorporated any new disclosure requirements into our 2017 financial statements and footnotes included in Exhibit 99.1 of our Form 8-K filed on May 7, 2018. See Note 1 of our 2017 financial statements and footnotes included in Exhibit 99.1 in our Form 8-K filed on May 7, 2018 for additional discussion related to revenue accounting policies and disclosures. In addition, see Note 16 of our 2017 financial statements and footnotes included in Exhibit 99.1 of our Form 8-K filed on May 7, 2018 for receivables related to sales of oil, natural gas and related products and services. The composition of our receivables as of June 30, 2018 has not changed significantly as compared to December 31, 2017.
We adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, effective January 1, 2018 which requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows on a retrospective basis. The requirements of this standard are reflected on our Consolidated Statement of Cash Flows, including prior periods. Restricted cash was approximately $13 million and $12 million as of June 30, 2018 and December 31, 2017, respectively.
We adopted ASU 2017-01, Business Combinations, clarifying the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses effective January 1, 2018.
We adopted ASU 2017-09, Compensation - Stock Compensation (Topic 718), effective January 1, 2018. This ASU provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The adoption of this standard did not have a significant impact on our consolidated financial statements.
Accounting Standards Not Yet Adopted
In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases, to increase transparency and comparability among organizations through recognition of right-of-use assets and lease payment liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under ASU 2016-02, a determination is to be made at the inception of a contract as to whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. ASU 2016-02 permits lessees to make alternative policy elections (“practical expedients”) to not recognize right-of-use assets and lease payment liabilities for leases with terms of less than twelve months and/or to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize right-of-use assets and lease payment liabilities related to certain drilling rig commitments, certain equipment leases, and potentially other arrangements. We are in the process of evaluating our contracts with components that may be subject to ASU 2016-02 and have engaged a third party to assist with implementing the standard. In 2018 and 2019, we will implement appropriate changes to our business processes, systems or controls to support recognition and disclosure under the new standard. Our findings and progress toward implementation of the standard are periodically reported to management. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. In July 2018, the FASB amended this guidance to ease the transition requirements by providing an adoption alternative that allows entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption in lieu of retrospectively applying the guidance to pre-adoption periods. The Company continues to evaluate the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements and related disclosures and the practical expedients we will utilize upon implementation of the standard. We do not intend to adopt the standard early.
In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to not evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under the original “Leases (Topic 840)” accounting standard (“Topic 840”). The Company enters into land easements on a routine basis as part of our ongoing operations and has many such agreements currently in place. The Company does not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, the Company will assess any land easements entered into (or modified) on or after adoption of ASU 2016-02 to determine whether the arrangement should be accounted for as a lease.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815). This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The amendments in this Update are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.
v3.10.0.1
Discontinued Operations Discontinued Operations (Notes)
6 Months Ended
Jun. 30, 2018
Discontinued operations [Abstract]  
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]
Discontinued Operations
On January 30, 2018, we signed an agreement to sell our properties in the San Juan Gallup oil play to Enduring Resources IV, LLC (“Enduring”) for $700 million (subject to closing and post-closing adjustments). The transaction closed on March 28, 2018 and we received approximately $667 million (subject to post-closing adjustments). In addition, the purchaser assumed approximately $309 million of gathering and processing commitments; however, WPX has left in place a performance guarantee with respect to these commitments. We believe that any future performance under this guarantee obligation is highly unlikely given our understanding of the buyer’s credit position, the indemnity arrangement between the Company and Enduring and the declining size of the obligations subject to the guarantee over time. Although we believe the probability of performance by WPX is low, we must determine the fair value of the guarantee that was provided. We estimated the fair value of the guarantee to be approximately $9 million based on the factors mentioned above along with projections of estimated future volume throughputs and risk adjusted discount rates, all of which are Level 3 inputs. This amount is included in our calculation of the loss on sale. We recorded a total loss on the sale of $147 million in 2018. The operations in the San Juan Gallup represented 12 percent of our total proved reserves at December 31, 2017 and 16 percent of our total production for 2017.
As previously noted, we sold our San Juan Legacy properties in December 2017. As a result of the dispositions of San Juan Gallup and San Juan Legacy properties, we no longer have operations in the San Juan Basin. Our discontinued operations consist of the previously owned properties in the San Juan Basin and accretion on certain transportation and gathering obligations retained and recognized in prior years related to the sale of Powder River properties.
Summarized Results of Discontinued Operations
The following table presents the results of our discontinued operations for the periods presented.
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(Millions)
Total revenues
$

 
$
63

 
$
75

 
$
129

Costs and expenses:
 
 
 
 
 
 
 
Depreciation, depletion and amortization
$

 
$
30

 
$
8

 
$
64

Lease and facility operating

 
12

 
7

 
24

Gathering, processing and transportation

 
15

 
12

 
31

Taxes other than income

 
4

 
5

 
10

General and administrative

 
2

 
1

 
4

Exploration

 
5

 
3

 
8

Gain on sales of assets

 

 

 
(4
)
Accretion for transportation and gathering obligations retained
1

 
1

 
3

 
3

Other—net

 

 
4

 
1

Total costs and expenses
1

 
69

 
43

 
141

Operating income (loss)
(1
)
 
(6
)
 
32

 
(12
)
Loss on sale of assets
(1
)
 

 
(150
)
 

Loss from discontinued operations before income taxes
(2
)
 
(6
)
 
(118
)
 
(12
)
Income tax provision (benefit)

 
245

 
(27
)
 
242

Loss from discontinued operations
$
(2
)
 
$
(251
)
 
$
(91
)
 
$
(254
)

Assets and Liabilities in the Consolidated Balance Sheets attributable to Discontinued Operations
The following table presents assets classified as held for sale and liabilities associated with assets held for sale related to our San Juan Basin operations.
 
December 31,
 
2017
 
(Millions)
Assets classified as held for sale
 
Inventories
$
14

Properties and equipment, net (successful efforts method of accounting)
797

Total assets classified as held for sale on the Consolidated Balance Sheets
$
811

 
 
Liabilities associated with assets held for sale
 
Current liabilities:
 
Accounts payable
$
1

Accrued and other current liabilities
1

Total current liabilities
2

Asset retirement obligations
15

Other noncurrent liabilities
3

Total liabilities associated with assets held for sale on the Consolidated Balance Sheets
$
20



Cash Flows Attributable to Discontinued Operations
In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $28 million and $29 million for the six months ended June 30, 2018 and 2017, respectively.
 
Six months
ended June 30,
 
2018
 
2017
 
(Millions)
Cash provided by operating activities(a)
$
45

 
$
55

Cash capital expenditures within investing activities
$
29

 
$
77

__________
(a) Excluding income taxes and changes in working capital items.
v3.10.0.1
Earnings (Loss) Per Common Share from Continuing Operations
6 Months Ended
Jun. 30, 2018
Earnings Per Share [Abstract]  
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
The following table summarizes the calculation of earnings per share.
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(Millions, except per-share amounts)
Income (loss) from continuing operations
$
(79
)
 
$
327

 
$
(105
)
 
$
422

Less: Dividends on preferred stock
4

 
4

 
8

 
8

Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share
$
(83
)
 
$
323

 
$
(113
)
 
$
414

 
 
 
 
 
 
 
 
Basic weighted-average shares
400.0

 
397.8

 
399.3

 
392.1

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

 
1.5

 

 
2.7

Stock options

 
0.1

 

 
0.2

Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock

 
23.8

 

 
23.8

Diluted weighted-average shares
400.0

 
423.2

 
399.3

 
418.8

Earnings (loss) per common share from continuing operations:
 
 
 
 
 
 
 
Basic
$
(0.21
)
 
$
0.81

 
$
(0.28
)
 
$
1.06

Diluted
$
(0.21
)
 
$
0.77

 
$
(0.28
)
 
$
1.01


__________
(a) The following table includes amounts that have been excluded from the computation of diluted earnings (loss) 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. The excluded amounts are as follows:
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2018
 
2018
 
(Millions)
Weighted-average nonvested restricted stock units and awards
2.9

 
3.0

Weighted-average stock options
0.2

 
0.2

Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock
19.8

 
19.8



The table below includes information related to stock options that were outstanding at June 30, 2018 and 2017 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the second quarter weighted-average market price of our common shares.
 
June 30,
 
2018
 
2017
Options excluded (millions)
0.6

 
1.9

Weighted-average exercise price of options excluded
$
18.73

 
$
16.68

Exercise price range of options excluded
$17.47 - $21.81

 
$11.75 - $21.81

Second quarter weighted-average market price
$
17.12

 
$
11.40


The diluted weighted-average shares excludes the effect of approximately 0.7 million and 2.0 million nonvested restricted stock units for the six months ended June 30, 2018 and 2017, respectively. These restricted stock units were antidilutive under the treasury stock method.
v3.10.0.1
Asset Sales and Exploration Expense
6 Months Ended
Jun. 30, 2018
Extractive Industries [Abstract]  
Asset Sales, Exploration Expenses And Other Accruals [Text Block]
Asset Sales and Exploration Expenses
Asset Sales
Net gain on sales of assets for the three and six months ended June 30, 2017 includes a gain from exchanges of leasehold acreage in the Delaware Basin, a net gain recognized on the sales of certain Green River Basin and Appalachian Basin assets and recognition of deferred gain related to the completion of commitments from the sale of a gathering system in prior years.
In conjunction with exchanges of leasehold, we estimate the fair value of the leasehold through discounted cash flow models and consideration of market data. Our estimates and assumptions include future commodity prices, projection of estimated quantities of oil and natural gas reserves, expectations for future development and operating costs and risk adjusted discount rates, all of which are Level 3 inputs.
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(Millions)
Unproved leasehold property impairment, amortization and expiration
$
16

 
$
15

 
$
33

 
$
50

Geologic and geophysical costs
1

 
1

 
3

 
2

Total exploration expenses
$
17

 
$
16

 
$
36

 
$
52



Unproved leasehold property impairment, amortization and expiration for the six months ended June 30, 2017 includes costs in excess of the accumulated amortization balance associated with certain leases in the Delaware Basin that expired during the first quarter of 2017. These leases were renewed in second-quarter 2017.
v3.10.0.1
Inventories
6 Months Ended
Jun. 30, 2018
Inventory Disclosure [Abstract]  
Inventories
Inventories
The following table presents a summary of our inventories as of the dates indicated below.
 
June 30,
2018
 
December 31,
2017
 
(Millions)
Material, supplies and other
$
39

 
$
29

Crude oil production in transit
1

 
1

     Total inventories
$
40

 
$
30

v3.10.0.1
Debt and Banking Arrangements
6 Months Ended
Jun. 30, 2018
Debt Disclosure [Abstract]  
Debt and Banking Arrangements
Debt and Banking Arrangements
The following table presents a summary of our debt as of the dates indicated below.
 
June 30,
2018
 
December 31,
2017
 
(Millions)
Credit facility agreement
$

 
$

7.500% Senior Notes due 2020

 
350

6.000% Senior Notes due 2022
529

 
1,100

8.250% Senior Notes due 2023
500

 
500

5.250% Senior Notes due 2024
650

 
650

5.750% Senior Notes due 2026
500

 

     Total long-term debt
$
2,179

 
$
2,600

Less: Debt issuance costs on long-term debt(a)
25

 
25

Total long-term debt, net(a)
$
2,154

 
$
2,575

__________
(a) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
Credit Facility    
As of June 30, 2018, we had no borrowings outstanding and $65 million of letters of credit issued under the Credit Facility and we were in compliance with our financial covenants with full access to the Credit Facility.    
On April 17, 2018, the Company entered into a Second Amendment to Second Amended and Restated Credit 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, as amended, increases total commitments to $1.5 billion, increases the Borrowing Base to $1.8 billion, and extends the maturity date to April 17, 2023, subject to a springing maturity on October 15, 2021 if available liquidity minus outstanding 2022 notes is less than $500 million. Based on our current credit ratings, a Collateral Trigger Period applies which makes the Credit Facility subject to certain financial covenants and a Borrowing Base as described below. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time.
Borrowing Base. During a Collateral Trigger Period, loans under the Credit Facility are subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. The $1.8 billion Borrowing Base will remain in effect until the next Redetermination Date as set forth in the Credit Facility and at this time, availability under the Credit Facility Agreement is limited by the total commitments of $1.5 billion. The Borrowing Base is recalculated at least every six months per the terms of the Credit Facility.
Terms and Conditions. The Credit Facility will initially be guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding Midstream Assets). Such obligations shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility.
The Collateral Trigger Termination Date is the first date following the date of the closing of the Credit Facility and the first date following any Collateral Trigger Date, as applicable, on which (i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s.
Interest and Commitment Fees. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. As amended and during a Collateral Trigger Period, the applicable margin ranges from 0.25% to 1.25% per annum in the case of the alternate base rate, and from 1.25% to 2.25% per annum in the case of LIBOR. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. As amended and during a Collateral Trigger Period, the commitment fee ranges from 0.375% to 0.500% per annum. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to the Company’s senior unsecured debt ratings.
Significant Financial Covenants.
Pursuant to the amendment, the Company is required to maintain:
a ratio of Net Indebtedness to Consolidated EBITDAX for the most recent ended four consecutive fiscal quarters (excluding the first three quarters of 2018 which will use an Annualized Consolidated EBITDAX) of not greater than 4.25 to 1.00 as of the last day of the most recently ended Rolling Period; and
a ratio of consolidated current assets (including the unused amount of the Aggregate Commitments) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least 1.0 to 1.0.
If a Collateral Trigger Termination Date occurs, other financial covenants would apply and replace those listed above.
See Exhibit 99.1 of our Form 8-K filed May 7, 2018 for additional information on covenants related to our Credit Facility that were unchanged under the new amendment. As of the date of this filing, we are in compliance with all terms, conditions and financial covenants of the Credit Facility, as amended.
Senior Notes
In the second quarter of 2018, we used proceeds from our San Juan Gallup disposition and the issuance of new senior notes discussed below to retire $921 million aggregate principal amount of our senior notes ($350 million due 2020 and $571 million due 2022) through a series of cash tender offers. As a result of the debt tender offers, we recorded a loss on extinguishment of debt of $71 million, which includes approximately $63 million of premium and approximately $6 million write-off of previously capitalized costs.
On May 23, 2018, we completed a debt offering of $500 million of 5.750% Senior Notes due in 2026 (the “2026 Notes”). The notes are 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 June 1 and December 1 of each year commencing on December 1, 2018. The 2026 Notes will mature on June 1, 2026 with the option, prior to June 1, 2021, to redeem some or all of the notes at a specified “make whole” premium as described in the indenture governing the notes or, after June 1, 2021, we have the option to redeem the notes, in whole or in part, at the applicable redemption prices set forth in the indenture. The net proceeds from the offering of the 2026 Notes was approximately $494 million and approximately $1 million of debt issuance costs were capitalized.
See Exhibit 99.1 of our Form 8-K filed May 7, 2018, which includes the financial statements and footnotes for the year ended December 31, 2017, for additional discussion related to our senior notes.
v3.10.0.1
Provision (Benefit) for Income Taxes
6 Months Ended
Jun. 30, 2018
Income Tax Disclosure [Abstract]  
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
The following table presents the benefit for income taxes from continuing operations. 
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(Millions)
Current:
 
 
 
 
 
 
 
Federal
$

 
$

 
$

 
$

State

 

 

 

 

 

 

 

Deferred:
 
 
 
 
 
 
 
Federal
(28
)
 
(18
)
 
(37
)
 
28

State
(5
)
 
(280
)
 
(11
)
 
(293
)
 
(33
)
 
(298
)
 
(48
)
 
(265
)
Total benefit
$
(33
)
 
$
(298
)
 
$
(48
)
 
$
(265
)

The effective income tax rate for the three months ended June 30, 2018, differs from the new federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of state income taxes.
The effective income tax rate for the three months ended June 30, 2017, differs from the federal statutory rate of 35 percent due to the impact of equity-based compensation, the effect of state income taxes and other permanent items as applied by ASC 740 interim period allocation methodology.
The effective income tax rate for the six months ended June 30, 2018, differs from the new federal statutory rate of 21 percent due to the impact of equity-based compensation and the effect of an adjustment to state deferred taxes as a result of a decrease in the blended state income tax rate due to changes in state apportionment factors resulting from the divestment of our San Juan Basin assets.
The effective income tax rate for the six months ended June 30, 2017, differs from the federal statutory rate of 35 percent due to the impact of equity-based compensation, the effect of an adjustment to state deferred taxes as a result of a decrease in the blended state income tax rate due to changes in state apportionment factors resulting from increased presence in the Delaware Basin operations in Texas following the Panther acquisition and other permanent items as applied by ASC 740 interim period allocation methodology.
Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Tax Cuts and Jobs Act (“Act”), the SEC issued Staff Accounting Bulletin (“SAB”) 118 which allowed us to provide a provisional estimate of the impacts of the Act in our results of operations for December 31, 2017. Additional impacts from the enactment of the Act will be recorded as they are identified during the one-year measurement period as provided for in SAB 118. Our estimate does not reflect the impact of potential reductions of AMT credit refunds, changes in current interpretations of performance based executive compensation deduction limitations, effects of any state tax law changes and uncertainties regarding interpretations that may arise as a result of federal tax reform. The Company will continue to analyze the effects of the Act on its financial statements and operations and record changes to our estimates as appropriate.
We have recorded valuation allowances against deferred tax assets attributable primarily to certain state net operating loss (“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 may 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 other 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. We have not recorded a valuation allowance against our federal NOL carryover, but a valuation allowance could be required in future periods if the federal NOL carryover continues to increase or circumstances change.
The ability of WPX to utilize loss carryovers or minimum tax credits to reduce future federal taxable income and income tax could be subject to limitations under the Internal Revenue 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 June 30, 2018, 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.
Pursuant to our tax sharing agreement with 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. 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. In 2017, the IRS proposed an adjustment related to our business for which a payment to Williams could be required. We are currently evaluating the issue and expect to protest the adjustment within the normal appeals process of the IRS. 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. Any such adjustment to this deferred tax asset will not be known until the IRS examination is completed, but is not expected to result in a cash settlement unless we have utilized any of the alternative minimum tax credits.
As of June 30, 2018, the Company has approximately $8 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $7 million. Currently, we expect ultimate resolution of our uncertain tax position during the next 12 months.
v3.10.0.1
Contingent Liabilities
6 Months Ended
Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]  
Contingent Liabilities
Contingent Liabilities and Commitments
Contingent Liabilities
Royalty litigation
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, breach of implied duty to market, 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 March 2017, plaintiffs appealed the denial of class certification to the Tenth Circuit and oral argument before the Tenth Circuit was held on January 17, 2018. 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 injunctive relief. On August 16, 2016, the court denied plaintiffs’ motion for class certification. On September 15, 2016, plaintiffs filed their motion for reconsideration and filed a second motion for class certification, and on September 30, 2017, the Court issued its memorandum opinion and order denying the plaintiffs motion for reconsideration and their Second Motion for Class Certification. 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 many of 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. Similar guidelines were recently issued for certain leases in Colorado and, as in the case of the New Mexico guidelines, we do not believe that they will result in a material difference to our historical federal royalty payments. ONRR has asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas.
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 The Williams Companies, Inc. (“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.
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 Federal Energy Regulatory Commission 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 In re: Western States Wholesale 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. On March 7, 2016, the putative class plaintiffs in several of the cases filed their motions for class certification. On March 30, 2017, the court denied the motions for class certification, which decision was appealed on June 20, 2017. On May 24, 2016, in Reorganized FLI Inc. v. Williams Companies, Inc., the Court granted Defendants’ Motion for Summary Judgment in its entirety, and an agreed amended judgment was entered by the court on January 4, 2017. The parties have filed numerous motions for summary judgment, reconsideration and remand, and there are currently two appeals before the Ninth Circuit. 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 exposure at this time.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, including the agreements pursuant to which we divested our Piceance and San Juan Basin operations, 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 breaches of representations and warranties, tax liabilities, historic litigation, personal injury, environmental matters and rights-of-way. Additionally, Federal and state laws in areas of former operations may require previous operators to perform in certain circumstances where the buyer/operator may no longer be able to perform. Such duties may include plugging and abandoning wells or responsibility for surface agreements.
The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in that litigation have asserted claims regarding, among other things, the method by which we took transportation costs into account when calculating royalty payments. In 2017, we settled one of these claims.
As of June 30, 2018, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss beyond any amount already accrued. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
In connection with the separation from Williams, we agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.
Summary
As of June 30, 2018 and December 31, 2017, the Company had accrued approximately $11 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
Commitments
See Note 2 for a discussion of commitments that were assumed by the purchaser of our San Juan Gallup assets and a related existing performance guarantee from WPX that will remain in place.
v3.10.0.1
Fair Value Measurements
6 Months Ended
Jun. 30, 2018
Fair Value Disclosures [Abstract]  
Fair Value Measurements
Fair Value Measurements
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
June 30, 2018
 
December 31, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$

 
$
185

 
$

 
$
185

 
$

 
$
59

 
$

 
$
59

Energy derivative liabilities
$

 
$
452

 
$

 
$
452

 
$

 
$
236

 
$

 
$
236

Total debt(a)
$

 
$
2,255

 
$

 
$
2,255

 
$

 
$
2,746

 
$

 
$
2,746

__________
(a)
The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,179 million and $2,600 million as of June 30, 2018 and December 31, 2017, respectively. The fair value of our debt, which also excludes capital leases and debt issuance costs, is determined on market rates and the prices of similar securities with similar terms and credit ratings.
Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts may include forwards, swaps, options or swaptions. These are carried at fair value on the Consolidated Balance Sheets.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Forward, swap, option and swaption contracts are considered Level 2 and are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as calls and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold calls or swaptions establish a maximum price we will receive for the volumes under contract and are financially settled. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of over-the-counter products or like products and the tenure of our derivatives portfolio extends through the end of 2022. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a quarterly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. We had instruments totaling less than $1 million included in Level 3 as of June 30, 2018.
Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers occurred during the periods ended June 30, 2018 and 2017.
There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
v3.10.0.1
Derivatives and Concentration of Credit Risk
6 Months Ended
Jun. 30, 2018
Fair Value Disclosures [Abstract]  
Derivatives and Concentration of Credit Risk
 Derivatives and Concentration of Credit Risk
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of crude oil, natural gas and natural gas liquids attributable to commodity price risk.
We produce, buy and sell crude oil, natural gas and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements and financial option contracts to mitigate the price risk on forecasted sales of crude oil, natural gas and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are sold options.
Derivatives related to production
The following table sets forth the derivative notional volumes of the net long (short) positions that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of June 30, 2018.
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
 
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
Jul - Dec 2018
 
Fixed Price Swaps
 
WTI
 
(57,500
)
 
$
52.82

Crude Oil
 
Jul - Dec 2018
 
Basis Swaps
 
Midland-Cushing
 
(14,000
)
 
$
(0.77
)
Crude Oil
 
Jul - Dec 2018
 
Basis Swaps
 
Nymex CMA Roll
 
(16,630
)
 
$
0.03

Crude Oil
 
Jul - Dec 2018
 
Basis Swaps
 
Argus LLS
 
(4,158
)
 
$
7.01

Crude Oil
 
Jul - Dec 2018
 
Basis Swaps
 
Magellan East
 
(4,989
)
 
$
6.38

Crude Oil
 
Jul - Dec 2018
 
Fixed Price Calls
 
WTI
 
(13,000
)
 
$
58.89

Crude Oil
 
2019
 
Fixed Price Swaps
 
WTI
 
(36,000
)
 
$
52.86

Crude Oil
 
2019
 
Basis Swaps
 
Midland-Cushing
 
(21,008
)
 
$
(1.16
)
Crude Oil
 
2019
 
Basis Swaps
 
Nymex CMA Roll
 
(20,000
)
 
$
0.11

Crude Oil
 
2019
 
Fixed Price Calls
 
WTI
 
(5,000
)
 
$
54.08

Crude Oil
 
2020
 
Basis Swaps
 
Midland-Cushing
 
(7,486
)
 
$
(1.31
)
Crude Oil
 
2020
 
Basis Swaps
 
Brent/WTI Spread
 
(3,000
)
 
$
8.40

Crude Oil
 
2021
 
Basis Swaps
 
Brent/WTI Spread
 
(1,000
)
 
$
8.00

Crude Oil
 
2022
 
Basis Swaps
 
Brent/WTI Spread
 
(1,000
)
 
$
7.75

Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
Jul - Dec 2018
 
Fixed Price Swaps
 
Henry Hub
 
(130
)
 
$
2.99

Natural Gas
 
Jul - Dec 2018
 
Basis Swaps
 
Permian
 
(48
)
 
$
(0.31
)
Natural Gas
 
Jul - Dec 2018
 
Basis Swaps
 
Waha
 
(15
)
 
$
0.93

Natural Gas
 
Jul - Dec 2018
 
Basis Swaps
 
Houston Ship
 
(43
)
 
$
(0.08
)
Natural Gas
 
Jul - Dec 2018
 
Fixed Price Calls
 
Henry Hub
 
(16
)
 
$
4.75

Natural Gas
 
2019
 
Fixed Price Swaps
 
Henry Hub
 
(50
)
 
$
2.87

Natural Gas
 
2019
 
Basis Swaps
 
Permian
 
(25
)
 
$
(0.39
)
Natural Gas
 
2019
 
Basis Swaps
 
Waha
 
(25
)
 
$
1.31

Natural Gas
 
2019
 
Basis Swaps
 
Houston Ship
 
(30
)
 
$
(0.09
)
Natural Gas
 
2020
 
Basis Swaps
 
Waha
 
(40
)
 
$
(0.79
)
Natural Gas
 
2021
 
Basis Swaps
 
Waha
 
(20
)
 
$
(0.57
)
Natural Gas Liquids
 
 
 
 
 
 
 
 
 
 
Natural Gas Liquids
 
Jul - Dec 2018
 
Fixed Price Swaps
 
Mont Belvieu
 
(3,300
)
 
$
0.29

Natural Gas Liquids
 
Jul - Dec 2018
 
Fixed Price Swaps
 
Conway Propane
 
(900
)
 
$
0.79

Natural Gas Liquids
 
Jul - Dec 2018
 
Fixed Price Swaps
 
Mont Belvieu
 
(3,900
)
 
$
0.80

Natural Gas Liquids
 
Jul - Dec 2018
 
Fixed Price Swaps
 
Mont Belvieu Iso
 
(700
)
 
$
0.91

Natural Gas Liquids
 
Jul - Dec 2018
 
Fixed Price Swaps
 
Mont Belvieu
 
(1,800
)
 
$
0.90

Natural Gas Liquids
 
Jul - Dec 2018
 
Fixed Price Swaps
 
Mont Belvieu
 
(1,500
)
 
$
1.31

__________
(a)
Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls or swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls or swaptions. In connection with swaps, we may sell call options or swaptions to the swap counterparties in exchange for receiving premium hedge prices on the swaps. The sold call or swaption establishes a maximum price we will receive for the volumes under contract and are financially settled. Basis swaps for the Nymex CMA (Calendar Monthly Average) Roll location are pricing adjustments to the trade month versus the delivery month for contract pricing. Basis swaps for the Brent/WTI location are priced off the Brent and WTI futures spread. Derivatives related to natural gas liquids production are fixed price swaps.
(b)
Crude oil volumes are reported in Bbl/day, natural gas volumes are reported in BBtu/day and natural gas liquids volumes are reported in Bbl/day.
(c)
The weighted average price for crude oil is reported in $/Bbl, natural gas is reported in $/MMBtu and natural gas liquids is reported in $/Gal.
Fair values and gains (losses)
Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.
We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting for derivative instruments. Net gain (loss) on derivatives on the Consolidated Statements of Operations includes settlements to be paid of $78 million and $133 million for the three and six months ended June 30, 2018, respectively, and settlements received of $14 million and $9 million for the three and six months ended June 30, 2017, respectively.
The cash flow impact of our derivative activities is presented as separate line items within the operating activities on the Consolidated Statements of Cash Flows.
Offsetting of derivative assets and liabilities
The following table presents our gross and net derivative assets and liabilities.
 
Gross Amount Presented on Balance Sheet
 
Netting Adjustments (a)
 
Net Amount
June 30, 2018
(Millions)
Derivative assets with right of offset or master netting agreements
$
185

 
$
(138
)
 
$
47

Derivative liabilities with right of offset or master netting agreements
$
(452
)
 
$
138

 
$
(314
)
 
 
 
 
 
 
December 31, 2017
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
59

 
$
(42
)
 
$
17

Derivative liabilities with right of offset or master netting agreements
$
(236
)
 
$
42

 
$
(194
)
__________
(a)
With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
Credit-risk-related features
Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.
As of June 30, 2018, we had no collateral posted to derivative counterparties, to support the aggregate fair value of our net $314 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of $3 million to our liability balance for our own nonperformance risk. Assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, the additional collateral that we would have been required to post at June 30, 2018 was $314 million. 
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Accounts receivable
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.
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2018 and 2017, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.
Our gross and net credit exposure from our derivative contracts were $185 million and $47 million, respectively, as of June 30, 2018. Ninety-nine percent of our credit exposure is with investment grade financial institutions. We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 to be investment grade.
Our three largest net counterparty positions represent approximately 100 percent of our net credit exposure. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.
One of our senior officers is on the board of directors of NGL Energy Partners, LP ("NGL Energy"). In the normal course of business, we sell crude oil to NGL Energy. For the first six months of 2018, sales to NGL Energy were approximately 12 percent of our total consolidated revenues adjusted for loss on derivatives. In addition, a subsidiary of NGL Energy provides water disposal services for WPX that represent less than 1 percent of operating expenses.
Other
Collateral support for our commodity agreements could include margin deposits, letters of credit, surety bonds and guarantees of payment by credit worthy parties.
v3.10.0.1
Subsequent Event (Notes)
6 Months Ended
Jun. 30, 2018
Subsequent Events [Abstract]  
Subsequent Events [Text Block]
Subsequent Events
Based on the provisions of the mandatory convertible preferred stock offering in 2015, each share of our preferred stock would automatically convert into between 4.1254 and 4.9504 shares of our common stock (respectively, the “minimum conversion rate” and “maximum conversion rate”) on July 30, 2018, subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion is determined based on the average volume weighted average price per share of our common stock (the “VWAP”) over the 20 consecutive trading day period beginning on, and including, the 23rd scheduled trading day immediately preceding July 31, 2018, which is referred to as the “final averaging period.” Based on the VWAP for the final averaging period, the preferred shares converted to common shares at the minimum conversion rate of 4.1254. On July 30, 2018, approximately 4.8 million shares of our preferred stock converted into approximately 19.8 million shares of our common stock pursuant to the mandatory conversion provisions of the preferred stock offering.
v3.10.0.1
Basis of Presentation and Description of Business Accounting Policies (Policies)
6 Months Ended
Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]
Recently Adopted Accounting Standards
The Company adopted Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, effective January 1, 2018 using the modified retrospective method. The core principle of the guidance in ASU 2014-09 is 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. The adoption of ASU 2014-09 was not material to our revenues or operating income (loss) or to our consolidated balance sheet because our performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of our contracts will continue to be recognized as control of products is transferred to the customer. A majority of the Company’s sales contracts at June 30, 2018 have terms of less than one year. For such contracts, we have used the practical expedient in ASC 606-10-50-14 which exempts an entity from the requirement to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract with an original expected duration of one year or less. For sales contracts with terms greater than one year, we have utilized the practical expedient in ASC 606-10-50-14A, which provides that an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts for all products, each unit of production represents a separate performance obligation that is satisfied upon delivery of product to the customer, thus, future volumes to be delivered are wholly unsatisfied at the reporting period end. We incorporated any new disclosure requirements into our 2017 financial statements and footnotes included in Exhibit 99.1 of our Form 8-K filed on May 7, 2018. See Note 1 of our 2017 financial statements and footnotes included in Exhibit 99.1 in our Form 8-K filed on May 7, 2018 for additional discussion related to revenue accounting policies and disclosures. In addition, see Note 16 of our 2017 financial statements and footnotes included in Exhibit 99.1 of our Form 8-K filed on May 7, 2018 for receivables related to sales of oil, natural gas and related products and services. The composition of our receivables as of June 30, 2018 has not changed significantly as compared to December 31, 2017.
We adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, effective January 1, 2018 which requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows on a retrospective basis. The requirements of this standard are reflected on our Consolidated Statement of Cash Flows, including prior periods. Restricted cash was approximately $13 million and $12 million as of June 30, 2018 and December 31, 2017, respectively.
We adopted ASU 2017-01, Business Combinations, clarifying the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses effective January 1, 2018.
We adopted ASU 2017-09, Compensation - Stock Compensation (Topic 718), effective January 1, 2018. This ASU provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The adoption of this standard did not have a significant impact on our consolidated financial statements.
Description of New Accounting Pronouncements Not yet Adopted [Text Block]
Accounting Standards Not Yet Adopted
In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases, to increase transparency and comparability among organizations through recognition of right-of-use assets and lease payment liabilities on the balance sheet and disclosure of key information about leasing arrangements. Under ASU 2016-02, a determination is to be made at the inception of a contract as to whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. ASU 2016-02 permits lessees to make alternative policy elections (“practical expedients”) to not recognize right-of-use assets and lease payment liabilities for leases with terms of less than twelve months and/or to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize right-of-use assets and lease payment liabilities related to certain drilling rig commitments, certain equipment leases, and potentially other arrangements. We are in the process of evaluating our contracts with components that may be subject to ASU 2016-02 and have engaged a third party to assist with implementing the standard. In 2018 and 2019, we will implement appropriate changes to our business processes, systems or controls to support recognition and disclosure under the new standard. Our findings and progress toward implementation of the standard are periodically reported to management. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. In July 2018, the FASB amended this guidance to ease the transition requirements by providing an adoption alternative that allows entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption in lieu of retrospectively applying the guidance to pre-adoption periods. The Company continues to evaluate the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements and related disclosures and the practical expedients we will utilize upon implementation of the standard. We do not intend to adopt the standard early.
In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to not evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under the original “Leases (Topic 840)” accounting standard (“Topic 840”). The Company enters into land easements on a routine basis as part of our ongoing operations and has many such agreements currently in place. The Company does not account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, the Company will assess any land easements entered into (or modified) on or after adoption of ASU 2016-02 to determine whether the arrangement should be accounted for as a lease.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815). This ASU provides guidance for various components of hedge accounting including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The amendments in this Update are effective for public entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim period. The Company does not expect any significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.
v3.10.0.1
Discontinued Operations Discontinued Operation (Tables)
6 Months Ended
Jun. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]  
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]
Summarized Results of Discontinued Operations
The following table presents the results of our discontinued operations for the periods presented.
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(Millions)
Total revenues
$

 
$
63

 
$
75

 
$
129

Costs and expenses:
 
 
 
 
 
 
 
Depreciation, depletion and amortization
$

 
$
30

 
$
8

 
$
64

Lease and facility operating

 
12

 
7

 
24

Gathering, processing and transportation

 
15

 
12

 
31

Taxes other than income

 
4

 
5

 
10

General and administrative

 
2

 
1

 
4

Exploration

 
5

 
3

 
8

Gain on sales of assets

 

 

 
(4
)
Accretion for transportation and gathering obligations retained
1

 
1

 
3

 
3

Other—net

 

 
4

 
1

Total costs and expenses
1

 
69

 
43

 
141

Operating income (loss)
(1
)
 
(6
)
 
32

 
(12
)
Loss on sale of assets
(1
)
 

 
(150
)
 

Loss from discontinued operations before income taxes
(2
)
 
(6
)
 
(118
)
 
(12
)
Income tax provision (benefit)

 
245

 
(27
)
 
242

Loss from discontinued operations
$
(2
)
 
$
(251
)
 
$
(91
)
 
$
(254
)
Balance Sheet Disclosures by Disposal Groups, Including Discontinued Operations [Table Text Block]
Assets and Liabilities in the Consolidated Balance Sheets attributable to Discontinued Operations
The following table presents assets classified as held for sale and liabilities associated with assets held for sale related to our San Juan Basin operations.
 
December 31,
 
2017
 
(Millions)
Assets classified as held for sale
 
Inventories
$
14

Properties and equipment, net (successful efforts method of accounting)
797

Total assets classified as held for sale on the Consolidated Balance Sheets
$
811

 
 
Liabilities associated with assets held for sale
 
Current liabilities:
 
Accounts payable
$
1

Accrued and other current liabilities
1

Total current liabilities
2

Asset retirement obligations
15

Other noncurrent liabilities
3

Total liabilities associated with assets held for sale on the Consolidated Balance Sheets
$
20



Schedule of Disposal Groups Including Discontinued Operations Cash Flows [Table Text Block]
Cash Flows Attributable to Discontinued Operations
In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $28 million and $29 million for the six months ended June 30, 2018 and 2017, respectively.
 
Six months
ended June 30,
 
2018
 
2017
 
(Millions)
Cash provided by operating activities(a)
$
45

 
$
55

Cash capital expenditures within investing activities
$
29

 
$
77

__________
(a) Excluding income taxes and changes in working capital items.
v3.10.0.1
Earnings (Loss) Per Common Share from Continuing Operations (Tables)
6 Months Ended
Jun. 30, 2018
Earnings Per Share [Abstract]  
Schedule of Stock Options Outstanding Excluded from Computation of weighted-average stock
The table below includes information related to stock options that were outstanding at June 30, 2018 and 2017 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the second quarter weighted-average market price of our common shares.
 
June 30,
 
2018
 
2017
Options excluded (millions)
0.6

 
1.9

Weighted-average exercise price of options excluded
$
18.73

 
$
16.68

Exercise price range of options excluded
$17.47 - $21.81

 
$11.75 - $21.81

Second quarter weighted-average market price
$
17.12

 
$
11.40

Earnings (Loss) Per Common Share from Continuing Operations
The following table summarizes the calculation of earnings per share.
 
Three months
ended June 30,
 
Six months
ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(Millions, except per-share amounts)
Income (loss) from continuing operations
$
(79
)
 
$
327

 
$
(105
)
 
$
422

Less: Dividends on preferred stock
4

 
4

 
8

 
8

Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share
$
(83
)
 
$
323

 
$
(113
)
 
$
414

 
 
 
 
 
 
 
 
Basic weighted-average shares
400.0

 
397.8

 
399.3

 
392.1

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

 
1.5

 

 
2.7

Stock options

 
0.1

 

 
0.2

Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock

 
23.8