WPX ENERGY, INC., 10-Q filed on 11/2/2017
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2017
Nov. 1, 2017
Document Documentand Entity Information [Abstract]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Sep. 30, 2017 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q3 
 
Trading Symbol
WPX 
 
Entity Registrant Name
WPX ENERGY, INC. 
 
Entity Central Index Key
0001518832 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
398,156,921 
Consolidated Balance Sheet (Unaudited) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Current assets:
 
 
Cash and Cash Equivalents, at Carrying Value
$ 10 
$ 496 
Accounts receivable, net of allowance of $1 million as of September 30, 2017 and $3 million as of December 31, 2016
268 
168 
Derivative assets, current
61 
26 
Inventories
42 
32 
Assets classified as held for sale (Note 5)
237 
12 
Other
30 
20 
Total current assets
648 
754 
Properties and equipment (successful efforts method of accounting)
9,675 
7,986 
Less—accumulated depreciation, depletion and amortization
(2,291)
(1,829)
Properties and equipment, net
7,384 
6,157 
Derivative assets, noncurrent
34 
12 
Assets classified as held for sale (Note 5)
317 
Other noncurrent assets
29 
24 
Total assets
8,095 
7,264 
Current liabilities:
 
 
Accounts payable
369 
222 
Accrued and other current liabilities
150 
301 
Liabilities associated with assets held for sale (Note 5)
62 
Derivative liabilities, current
56 
152 
Total current liabilities
637 
677 
Deferred income taxes
276 
251 
Long-term debt, net
2,859 1
2,575 1
Derivative liabilities, noncurrent
26 
63 
Asset retirement obligations
37 
38 
Liabilities associated with assets held for sale (Note 5)
62 
Other noncurrent liabilities
98 
132 
Stockholders’ equity:
 
 
Preferred stock (100 million shares authorized at $0.01 par value; 4.8 million shares outstanding at September 30, 2017 and December 31, 2016)
232 
232 
Common stock (2 billion shares authorized at $0.01 par value; 398.1 million and 344.7 million shares issued and outstanding at September 30, 2017 and December 31, 2016)
Additional paid-in-capital
7,476 
6,803 
Accumulated deficit
(3,550)
(3,572)
Total stockholders’ equity
4,162 
3,466 
Total liabilities and equity
$ 8,095 
$ 7,264 
Consolidated Balance Sheet (Unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 1 
$ 3 
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
398,100,000 
344,700,000 
Consolidated Statement of Operations (Unaudited) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Product revenues:
 
 
 
 
Oil sales
$ 259 
$ 139 
$ 673 
$ 378 
Natural gas sales
38 
37 
122 
86 
Natural gas liquid sales
29 
12 
73 
27 
Total product revenues
326 
188 
868 
491 
Net gain (loss) on derivatives
(106)
38 
213 
(59)
Gas management
25 
17 
172 
Other
Total revenues
224 
251 
1,098 
605 
Costs and expenses:
 
 
 
 
Depreciation, depletion and amortization
169 
150 
487 
465 
Lease and facility operating
58 
40 
159 
123 
Gathering, processing and transportation
25 
19 
67 
55 
Taxes other than income
26 
14 
68 
41 
Exploration (Note 5)
20 
10 
80 
31 
General and administrative (including equity-based compensation of $7 million, $10 million, $23 million and $25 million for the respective periods)
42 1
51 1
131 1
159 1
Gas management
31 
17 
202 
Net (gain) loss—sales of assets, divestment of transportation contracts or impairment of producing properties (Note 5)
(56)
227 
(98)
25 
Other—net
10 
15 
14 
Total costs and expenses
291 
552 
926 
1,115 
Operating income (loss)
(67)
(301)
172 
(510)
Interest expense
(48)
(49)
(141)
(159)
Gain (Loss) on Extinguishment of Debt
(17)
(17)
Investment income and other
Income (loss) from continuing operations before income taxes
(130)
(350)
18 
(668)
Provision (benefit) for income taxes
20 
(132)
(2)
(227)
Income (loss) from continuing operations
(150)
(218)
20 
(441)
Income (loss) from discontinued operations
(1)
12 
Net income (loss)
(146)
(219)
22 
(429)
Preferred Stock Dividends, Income Statement Impact
11 
15 
Preferred Stock Conversions, Inducements
22 
22 
Net income (loss) available to WPX Energy, Inc. common stockholders
(149)
(245)
11 
(466)
Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share
(153)
(244)
(478)
Income (loss) from discontinued operations
$ 4 
$ (1)
$ 2 
$ 12 
Income (Loss) from Continuing Operations, Per Basic Share
$ (0.39)
$ (0.72)
$ 0.02 
$ (1.58)
Discontinued Operation, Income (Loss) from Discontinued Operation, Per Basic Share
$ 0.01 
$ 0.00 
$ 0.01 
$ 0.04 
Earnings Per Share, Basic
$ (0.38)
$ (0.72)
$ 0.03 
$ (1.54)
Weighted Average Number of Shares Outstanding, Basic
398.1 
341.5 
394.1 
302.8 
Income (Loss) from Continuing Operations, Per Diluted Share
$ (0.39)
$ (0.72)
$ 0.02 
$ (1.58)
Discontinued Operation, Income (Loss) from Discontinued Operation, Per Diluted Share
$ 0.01 
$ 0.00 
$ 0.01 
$ 0.04 
Earnings Per Share, Diluted
$ (0.38)
$ (0.72)
$ 0.03 
$ (1.54)
Weighted Average Number of Shares Outstanding, Diluted
398.1 2
341.5 2
396.2 2
302.8 2
[2] 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. Additionally, 23.8 million common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock have been excluded from the computation of diluted earnings per share for all periods presented as their inclusion would be antidilutive due to application of the if-converted method. Three monthsended September 30, Nine monthsended September 30, 2017 2016 2017 2016 (Millions)Weighted-average nonvested restricted stock units and awards1.6 2.4 — 1.8Weighted-average stock options0.1 — — —
Consolidated Statement of Operations (parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Non-cash equity-based compensation expense
$ 7 
$ 10 
$ 23 
$ 25 
Consolidated Statement of Changes in Equity (Unaudited) (USD $)
In Millions, unless otherwise specified
Total
Preferred Stock
Common Stock
Additional Paid-In- Capital
Accumulated Deficit
December 31, 2016 at Dec. 31, 2016
$ 3,466 
$ 232 
$ 3 
$ 6,803 
$ (3,572)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
Net income (loss)
22 
 
 
 
22 
Stock-based compensation
15 
 
 
15 
 
Stock Issued During Period, Value, New Issues
670 
 
669 
 
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings
(11)
 
 
(11)
 
September 30, 2017 at Sep. 30, 2017
$ 4,162 
$ 232 
$ 4 
$ 7,476 
$ (3,550)
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Operating Activities(a)
 
 
Net income (loss)
$ 22 
$ (429)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation Depletion And Amortization Including Discontinued Portion
487 
474 
Deferred Income Tax Expense Benefit From Continuing And Discontinued Operations
25 
(209)
Provision For Impairment Of Properties And Equipment Including Certain Exploration Expenses And Equity Method Investment
138 
29 
Net (gain) loss on derivatives in continuing operations
(213)
59 
Net settlements related to derivatives in continuing operations
23 
260 
Net loss on derivatives included in discontinued operations
46 
Amortization of stock-based awards
24 
27 
Loss on extinguishment of debt
17 
Net gain on sales of assets and divestment of transportation contracts
(157)
(28)
Cash provided (used) by operating assets and liabilities:
 
 
Accounts receivable
(112)
147 
Inventories
(6)
13 
Other current assets
(6)
Accounts payable
91 
(79)
Federal income taxes receivable (payable)
12 
(33)
Accrued and other current liabilities
(86)
(92)
Payments on liabilities accrued in 2015 for retained transportation and gathering contracts related to discontinued operations
(40)
(42)
Other, including changes in other noncurrent assets and liabilities
(35)
Net cash provided by operating activities(a)
228 1
114 1
Investing Activities(a)
 
 
Capital Expenditures
(855)2
(440)2
Proceeds from sales of assets
34 
1,140 
Payments related to divestment of transportation contracts
(238)
Purchase of business
(798)
Purchase of investment
(7)
Other
(2)
(2)
Net cash provided by (used in) investing activities(a)
(1,628)1
460 1
Financing Activities
 
 
Proceeds from common stock
671 
540 
Dividends paid on preferred stock
(11)
(15)
Payments related to induced conversion of preferred stock to common stock
(10)
Borrowings on credit facility
471 
380 
Payments on credit facility
(186)
(645)
Proceeds from Issuance of Long-term Debt
148 
Payments for retirement of long-term debt, including premium
(165)
(230)
Taxes paid for shares withheld
(11)
(5)
Payments for debt issuance costs and credit facility amendment fees
(2)
(3)
Other
(1)
(1)
Net cash provided by financing activities
914 
11 
Net increase (decrease) in cash and cash equivalents
(486)
585 
Cash and Cash Equivalents, at Carrying Value, Including Discontinued Operations
496 
38 
Cash and cash equivalents at end of period
10 
623 
Increase to properties and equipment
(911)
(424)
Changes In Related Accounts Payable
$ 56 
$ (16)
Basis of Presentation and Description of Business
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, North Dakota, New Mexico and Colorado. We specialize in development and production from tight-sands and shale formations in the Delaware, Williston and San Juan Basins. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include oil and natural gas purchased from third-party working interest owners in operated wells and the management of various commodity contracts, such as transportation and related derivatives.
In June 2017, we signed an agreement with Howard Energy Partners (“Howard”) to jointly develop oil gathering and natural gas processing infrastructure in the Stateline area of the Delaware Basin. Under the terms of the agreement, WPX and Howard will each have a 50 percent voting interest in the joint venture and Howard will serve as operator. At closing, WPX will contribute crude oil gathering and natural gas processing assets already in service and/or under construction, with a net book value of approximately $56 million as of September 30, 2017, and will receive a special cash distribution of $300 million plus capital expenditures in 2017. Howard will contribute $300 million in cash at closing and is obligated to fund the first $263 million of joint venture capital expenditures, including a $132 million carry for WPX. This transaction closed on October 18, 2017 and we received the $300 million special distribution plus $49 million for capital expenditures in 2017. We expect to account for this joint venture as an equity method investment. In connection with the joint venture, the company will dedicate its current and future leasehold interest in the Stateline area, representing 50,000 net acres in the Delaware Basin, pursuant to 20 year fixed-fee oil gathering and natural gas processing agreements. However, the agreements do not include any minimum volume commitments.    
In addition, we have sold other operations which are reported as discontinued operations, as discussed below.
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, 2016 in the Company’s Annual Report on Form 10-K. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2017, results of operations for the three and nine months ended September 30, 2017 and 2016, changes in equity for the nine months ended September 30, 2017 and cash flows for the nine months ended September 30, 2017 and 2016. 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 gas management activities of oil, natural gas and NGLs in the United States.
Discontinued Operations
See Note 3 for a discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations. Additionally, see Note 9 for a discussion of contingencies related to the former power business of The Williams Companies, Inc. (“Williams”) (most of which was disposed of in 2007).    
Recently Adopted Accounting Standards
In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting, as part of the Simplification Initiative. The areas for simplification in ASU 2016-09 involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is required for annual periods beginning after December 15, 2016. Under ASU 2016-09, on a prospective basis, companies will no longer record excess tax benefits and deficiencies in additional paid in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit on the statement of operations. Other portions of the standard are adopted using either a prospective, retrospective, or modified retrospective approach depending on the topic covered in the standard. The Company adopted this guidance effective January 1, 2017 which impacted (a) our income tax provision in 2017 due to the tax deficiency recognized for tax and (b) the operating and financing activities sections of our Consolidated Statement of Cash Flows to reflect tax payments related to shares withheld for taxes. Cash outflows of $11 million and $5 million for the nine months ended September 30, 2017 and 2016, respectively, would have been included in operating activities under previous guidance, but are now reflected in financing activities.
Accounting Standards Not Yet Adopted
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, and has updated it with additional ASUs. 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. ASU 2014-09, as amended, is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The FASB will permit companies to adopt the new standard early, but not before the original effective date of annual reporting periods beginning after December 15, 2016. ASU 2014-09 can be applied using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements.
In 2016, we performed an initial assessment of the impact of ASU 2014-09 with the assistance of an outside consultant. Our assessment was based on a bottoms-up approach, in which we analyzed our existing contracts and current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our contracts. In 2017, we further documented our conclusions around the impact of the standard 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.
Currently, we do not expect the impact of adopting ASU 2014-09 to be material to our total net revenues and 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. We will adopt this standard on January 1, 2018 and, based on our evaluation to date, we anticipate using the modified retrospective method. We have finalized the majority of our documentation and assessment of the impact of the standard on our financial results and related disclosures and anticipate minimal adjustments to our disclosures in future filings from the adoption of this standard.
In February 2016, the FASB issued ASU 2016-02, Leases, to increase transparency and comparability among organizations by recognizing right-of-use assets and lease payment liabilities on the balance sheet and disclosing 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 policy elections to not recognize lease assets and 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 drilling rig commitments, certain equipment leases, and potentially other arrangements, the effects of which cannot be estimated at this time. 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. The Company continues to evaluate the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements or related disclosures.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which will require entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption in an interim period is permitted, but any adjustments must be reflected as of the beginning of the fiscal year that includes that interim period. Restricted cash was approximately $13 million and $10 million as of September 30, 2017 and December 31, 2016, respectively. The Company does not expect any significant impact on its consolidated statement of cash flows from the adoption of the standard.
In January 2017, FASB issued 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. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years.
In February 2017, the FASB issued ASU 2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This ASU clarifies the scope and application of ASC 610-20 on the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The amendments are effective at the same time as the new revenue standard. For public entities, the amendments are effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted. The Company does not expect any significant impact on its consolidated financial statements from the adoption of the standard.
In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718). The amendments in this Update provide 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 amendments in this Update are effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. 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 the standard.
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.
Acquisitions (Notes)
Oil and Gas Properties [Text Block]
Acquisition
On January 12, 2017, we signed an agreement to acquire certain assets from Panther Energy Company II, LLC and Carrier Energy Partners, LLC (the “Panther Acquisition”) for $775 million, subject to post-closing adjustments. The transaction closed in March 2017 for $798 million including estimated closing adjustments. The assets, as of the closing date, include 25 producing wells (18 horizontals), three drilled but uncompleted horizontal laterals, approximately 18,000 net acres and more than 900 gross undeveloped locations in the Delaware Basin. As of September 30, 2017, we estimate that approximately $599 million of the purchase price is allocable to unproved properties and approximately $200 million is allocable to proved properties and facilities. This estimate is based on discounted cash flow models, 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. At the time of the acquisition closing, production was approximately 10,000 Boe per day. The impact of this acquisition to prior periods is not material to our results of operations for those periods.
Discontinued Operations Discontinued Operations (Notes)
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]
Discontinued Operations
On February 8, 2016, we signed an agreement with Terra Energy Partners LLC to sell WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations. The parties closed this sale in April of 2016 for proceeds of $862 million. The amounts in the table below for 2016 primarily relate to the Piceance Basin. The income from discontinued operations for the three and nine months ended September 30, 2017 on the Consolidated Statement of Operations primarily relates to $10 million of Piceance Basin severance tax refunds for prior years that were received in third-quarter 2017. The refund was offset by continued accretion on retained transportation and gathering contracts related to Powder River Basin assets that were sold in 2015.
Summarized Results of Discontinued Operations
 
Three months ended September 30, 2016
 
Nine months ended September 30, 2016
 
(Millions)
Total revenues(a)
$

 
$
64

Costs and expenses:
 
 
 
Depreciation, depletion and amortization
$

 
$
9

Lease and facility operating

 
18

Gathering, processing and transportation
1

 
49

Taxes other than income
1

 
2

General and administrative
1

 
9

Other—net
(2
)
 
4

Total costs and expenses
1

 
91

Operating loss
(1
)
 
(27
)
Gain on sale of assets
1

 
53

Income from discontinued operations before income taxes

 
26

Income tax provision(b)
1

 
14

Income (loss) from discontinued operations
$
(1
)
 
$
12


__________
(a) The nine months ended September 30, 2016 include $33 million net loss on derivatives.
(b) The nine months ended September 30, 2016 includes a valuation allowance on certain state tax carryovers.

Cash Flows Attributable to Discontinued Operations
Excluding income taxes and changes to working capital, total cash provided by discontinued operations was $28 million for the nine months ended September 30, 2016. In addition, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $40 million and $42 million for the nine months ended September 30, 2017 and 2016, respectively. Total cash used in investing activities related to discontinued operations was $32 million for the nine months ended September 30, 2016.
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
The following table summarizes the calculation of earnings per share.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(Millions, except per-share amounts)
Income (loss) from continuing operations
$
(150
)
 
$
(218
)
 
$
20

 
$
(441
)
Less: Dividends on preferred stock
3

 
4

 
11

 
15

Less: Loss on induced conversion of preferred stock

 
22

 

 
22

Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share
$
(153
)
 
$
(244
)
 
$
9

 
$
(478
)
 
 
 
 
 
 
 
 
Basic weighted-average shares
398.1

 
341.5

 
394.1

 
302.8

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

 

 
1.9

 

Stock options

 

 
0.2

 

Diluted weighted-average shares
398.1

 
341.5

 
396.2

 
302.8

Earnings (loss) per common share from continuing operations:
 
 
 
 
 
 
 
Basic
$
(0.39
)
 
$
(0.72
)
 
$
0.02

 
$
(1.58
)
Diluted
$
(0.39
)
 
$
(0.72
)
 
$
0.02

 
$
(1.58
)

__________
(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. Additionally, 23.8 million common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock have been excluded from the computation of diluted earnings per share for all periods presented as their inclusion would be antidilutive due to application of the if-converted method.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(Millions)
Weighted-average nonvested restricted stock units and awards
1.6

 
2.4

 

 
1.8

Weighted-average stock options
0.1

 

 

 



The table below includes information related to stock options that were outstanding at September 30, 2017 and 2016 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.
 
September 30,
 
2017
 
2016
Options excluded (millions)
1.9

 
2.4

Weighted-average exercise price of options excluded
$
16.69

 
$
16.46

Exercise price range of options excluded
$11.75 - $21.81

 
$11.75 - $21.81

Third quarter weighted-average market price
$
10.23

 
$
11.11


The diluted weighted-average shares excludes the effect of approximately 2.0 million and 0.1 million nonvested restricted stock units for the nine months ended September 30, 2017 and 2016, respectively. These restricted stock units were antidilutive under the treasury stock method.
Asset Sales and Exploration Expense
Asset Sales, Exploration Expenses And Other Accruals [Text Block]
Asset Sales, Impairments and Exploration Expenses
Asset Sales and Impairments
2017
In the third quarter of 2017, we began a process to market our natural gas-producing properties in the San Juan Basin and our Board of Directors approved a divestment subject to a minimum price. These assets and liabilities were classified as held for sale on the Consolidated Balance Sheets at September 30, 2017 and December 31, 2016. Following the marketing process, we received several acceptable bids. As a result, we determined the estimated fair value, less costs to sell, based on the probability-weighted cash flows of expected proceeds and compared it to our net book value at September 30, 2017 which resulted in an impairment of $60 million recorded in third-quarter 2017. On October 26, 2017, we signed an agreement to sell the properties for $169 million, subject to closing adjustments, and expect to close by the end of 2017.
Net gain on sales of assets for the three and nine months ended September 30, 2017 includes gains from exchanges of leasehold acreage in the Permian Basin and $48 million and $56 million, respectively, from the recognition of deferred gains related to the completion of commitments from the sales of gathering systems in prior years. Net gain on sales of assets for the nine months ended September 30, 2017 also includes $8 million recognized on the sales of certain Green River Basin and Appalachian Basin assets.
In conjunction with exchanges of leasehold, we estimated 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.
2016
During July 2016, we completed the divestment of the remaining transportation contracts primarily related to our Piceance Basin operations which eliminated certain pipeline capacity obligations held by our marketing company, which were not included in the Piceance Basin divestment to Terra. As a result of the divestments and net payment of $238 million, we recorded a net loss of $238 million in third-quarter 2016.
On March 9, 2016, we completed the sale of our San Juan Basin gathering system for consideration of approximately $309 million. The consideration reflected $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 were obligated to complete certain in-progress construction as of the closing which resulted in the deferral of a portion of the gain. As a result of this transaction, we recorded a gain of $199 million in first-quarter 2016 and additional gains of $5 million and $11 million in the second and third quarters of 2016, respectively, as certain in-progress construction was completed.
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(Millions)
Unproved leasehold property impairment, amortization and expiration
$
20

 
$
9

 
$
78

 
$
28

Geologic and geophysical costs

 
1

 
2

 
2

Dry hole costs

 

 

 
1

Total exploration expenses
$
20

 
$
10

 
$
80

 
$
31



Unproved leasehold property impairment, amortization and expiration for the nine months ended September 30, 2017 includes costs in excess of the accumulated amortization balance associated with certain leases in the Permian Basin that expired during the first quarter of 2017. These leases were renewed in second-quarter 2017.
Inventories
Inventories
Inventories
The following table presents a summary of our inventories as of the dates indicated below.
 
September 30,
2017
 
December 31,
2016
 
(Millions)
Material, supplies and other
$
39

 
$
30

Crude oil production in transit
3

 
2

     Total inventories
$
42

 
$
32


During the third quarter of 2016, we recorded an impairment of material and supplies inventory of approximately $4 million.
Debt and Banking Arrangements
Debt and Banking Arrangements
Debt and Banking Arrangements
The following table presents a summary of our debt as of the dates indicated below.
 
September 30,
2017
 
December 31,
2016
 
(Millions)
Credit facility agreement
$
285

 
$

7.500% Senior Notes due 2020
350

 
500

6.000% Senior Notes due 2022
1,100

 
1,100

8.250% Senior Notes due 2023
500

 
500

5.250% Senior Notes due 2024
650

 
500

Other

 
1

     Total long-term debt
$
2,885

 
$
2,601

Less: Debt issuance costs on long-term debt(a)
26

 
26

Total long-term debt, net(a)
$
2,859

 
$
2,575


__________
(a) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
Our $1.2 billion senior secured revolving credit facility (“Credit Facility”) has a maturity date of October 28, 2019. As of September 30, 2017, we had $285 million borrowed and $75 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. Subsequent to September 30, 2017, we repaid all of the outstanding loans on our revolving credit facility with proceeds received from the closing of the Howard transaction.
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. As of December 31, 2016, the Borrowing Base was $1.025 billion. The Borrowing Base was increased to $1.2 billion in April 2017. In October 2017, the Borrowing Base was increased to 1.5 billion which will remain in effect until the next Redetermination Date as set forth in the Credit Facility Agreement. At this time, the Credit Facility Agreement is limited by the total commitments on the Credit Facility which remained at $1.2 billion. The Borrowing Base is recalculated at least every six months per the terms of the Credit Facility.
During third-quarter 2017, we issued an additional $150 million of our 5.25% senior notes due 2024. The proceeds were used to fund the tender offer of $150 million of our 7.50% senior notes due 2020.  As a result, we recorded a loss on extinguishment of debt of $17 million.
See our Annual Report on Form 10-K for the year ended December 31, 2016 for additional discussion related to our Credit Facility and our senior notes.
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
The following table presents the provision (benefit) for income taxes from continuing operations. 
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(Millions)
Current:
 
 
 
 
 
 
 
Federal
$
(27
)
 
$

 
$
(27
)
 
$

State

 
(5
)
 

 
(5
)
 
(27
)
 
(5
)
 
(27
)
 
(5
)
Deferred:
 
 
 
 
 
 
 
Federal
(12
)
 
(117
)
 
39

 
(236
)
State
59

 
(10
)
 
(14
)
 
14

 
47

 
(127
)
 
25

 
(222
)
Total provision (benefit)
$
20

 
$
(132
)
 
$
(2
)
 
$
(227
)

The effective income tax rate for the three months ended September 30, 2017, differs from the federal statutory rate due to the effect of state income taxes and other permanent items, as applied by ASC 740 interim period allocation methodology based on an estimated full year pre-tax loss.
The effective income tax rate for the nine months ended September 30, 2017, differs from the federal statutory rate due to the effect of state income taxes such as the decrease of 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 (see Note 2), the impact of ASU 2016-09 (see Note 1), and other permanent items, as applied by ASC 740 interim period allocation methodology based on an estimated full year pre-tax loss.
The effective income tax rate for the three months ended September 30, 2016, differs from the federal statutory rate due to the effects of state income taxes.
The effective income tax rate for the nine months ended September 30, 2016, differs from the federal statutory rate due to state tax adjustments resulting from the sale of our Piceance Basin operations in Colorado. In 2016, we recorded $8 million of valuation allowances against Colorado state tax loss and credit carryovers generated in prior years. We also increased our blended state income tax rate by less than one half percent to reflect changes in our then expected future apportionment among the states where we operate which resulted in a $14 million increase of our deferred tax liability as of the beginning of the year.
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. When assessing the need for a valuation allowance for the federal NOL carryover, we primarily consider future reversals of existing taxable temporary differences.
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 September 30, 2017, 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. The IRS has recently 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. Based on the IRS position and underlying arguments available to us at this time, we do not believe reserve accruals are necessary. 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.
As of September 30, 2017, the Company had 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
Contingent Liabilities
Contingent Liabilities and Commitments
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. 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.
Matter related to Williams’ former power business
In connection with a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us for the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications.
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor.
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 agreement pursuant to which we divested our Piceance 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. 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.
As of September 30, 2017, 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 September 30, 2017 and December 31, 2016, respectively, the Company had accrued approximately $11 million and $13 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
During the second quarter of 2017, we signed long-term transportation agreements that will ultimately provide 300,000 MMBtu per day (15 years) and 200,000 MMBtu per day (11 years) of natural gas capacity from our Delaware Basin properties in the Stateline area to markets in Texas. One of the agreements allows us the option to increase our capacity over time by 200,000 MMBtu per day to a total of 500,000 MMBtu per day. Total commitments related to these agreements, excluding the option, were approximately $337 million as of September 30, 2017.
Stockholder's Equity
Stockholders' Equity Note Disclosure [Text Block]
Note 10. Stockholders’ Equity
On January 12, 2017, we completed an underwritten public offering of 51.675 million shares of our common stock, which included 6.675 million shares of common stock issued pursuant to an option granted to the underwriters to purchase additional shares. The stock was sold to the underwriters at $12.97 per share and we received proceeds of approximately $670 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
On July 20, 2016, we entered into conversion agreements with certain owners of our preferred stock in which they agreed to convert shares of our preferred stock into shares of our common stock and, in addition, receive a $10 million cash payment from us in connection with the conversion. As a result of the cash payment and additional shares issued as an inducement to the holders of our preferred stock, we recorded a loss of $22 million in the third quarter of 2016.
Fair Value Measurements
Fair Value Measurements
Fair Value Measurements
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
September 30, 2017
 
December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$

 
$
95

 
$

 
$
95

 
$

 
$
38

 
$

 
$
38

Energy derivative liabilities
$

 
$
82

 
$

 
$
82

 
$

 
$
215

 
$

 
$
215

Total debt(a)
$

 
$
3,007

 
$

 
$
3,007

 
$

 
$
2,702

 
$

 
$
2,702

__________
(a)
The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,885 million and $2,600 million as of September 30, 2017 and December 31, 2016, 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 include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Forward, swap, option and swaption contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars, calls or swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several crude oil and natural gas swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of over-the-counter products or like products and the tenure of our derivatives portfolio extends through the end of 2020. 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 did not have any instruments included in Level 3 as of September 30, 2017.
Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers occurred during the periods ended September 30, 2017 and 2016.
There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
Derivatives and Concentration of Credit Risk
Derivatives and Concentration of Credit Risk
 Derivatives and Concentration of Credit Risk
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of 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 either purchased or sold options, or a combination of options that comprise a net purchased option, zero-cost collar or swaptions.
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 September 30, 2017.
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
 
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
Oct - Dec 2017
 
Fixed Price Swaps
 
WTI
 
(50,638
)
 
$
50.23

Crude Oil
 
Oct - Dec 2017
 
Basis Swaps
 
Midland-Cushing
 
(15,000
)
 
$
(0.62
)
Crude Oil
 
Oct - Dec 2017
 
Fixed Price Calls
 
WTI
 
(4,500
)
 
$
56.47

Crude Oil
 
2018
 
Fixed Price Swaps
 
WTI
 
(55,500
)
 
$
(52.69
)
Crude Oil
 
2018
 
Basis Swaps
 
Midland-Cushing
 
(17,521
)
 
$
(0.91
)
Crude Oil
 
2018
 
Basis Swaps
 
Nymex CMA Roll
 
(16,000
)
 
$
0.03

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

Crude Oil
 
2019
 
Fixed Price Swaps
 
WTI
 
(22,000
)
 
$
50.85

Crude Oil
 
2019
 
Basis Swaps
 
Midland-Cushing
 
(19,000
)
 
$
(0.93
)
Crude Oil
 
2019
 
Basis Swaps
 
Nymex CMA Roll
 
(4,000
)
 
$
0.07

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

   Crude Oil
 
2020
 
Basis Swaps
 
Midland-Cushing
 
(5,000
)
 
$
(1.16
)
Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
Oct - Dec 2017
 
Fixed Price Swaps
 
Henry Hub
 
(170
)
 
$
3.02

Natural Gas
 
Oct - Dec 2017
 
Basis Swaps
 
Permian
 
(73
)
 
$
(0.20
)
Natural Gas
 
Oct - Dec 2017
 
Basis Swaps
 
San Juan
 
(98
)
 
$
(0.18
)
Natural Gas
 
Oct - Dec 2017
 
Fixed Price Calls
 
Henry Hub
 
(15
)
 
$
4.50

Natural Gas
 
2018
 
Fixed Price Swaps
 
Henry Hub
 
(185
)
 
$
2.98

Natural Gas
 
2018
 
Basis Swaps
 
Permian
 
(43
)
 
$
(0.28
)
Natural Gas
 
2018
 
Basis Swaps
 
San Juan
 
(50
)
 
$
(0.34
)
Natural Gas
 
2018
 
Basis Swaps
 
Waha
 
(40
)
 
$
0.02

Natural Gas
 
2018
 
Basis Swaps
 
Houston Ship
 
(23
)
 
$
(0.08
)
Natural Gas
 
2018
 
Fixed Price Swaptions
 
Henry Hub
 
(20
)
 
$
3.33

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

Natural Gas
 
2019
 
Basis Swaps
 
Permian
 
(20
)
 
$
(0.34
)
Natural Gas
 
2019
 
Basis Swaps
 
Waha
 
(70
)
 
$
(0.15
)
Natural Gas
 
2019
 
Basis Swaps
 
Houston Ship
 
(10
)
 
$
(0.09
)
__________
(a)
Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with several crude oil and natural gas swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions grant the counterparty the option to enter into future swaps with us. 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.
(b)
Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.
(c)
The weighted average price for crude oil is reported in $/Bbl and natural gas is reported in $/MMBtu.
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 received of $14 million and $59 million for the three months ended September 30, 2017 and 2016, respectively, and $23 million and $260 million for the nine months ended September 30, 2017 and 2016, 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
September 30, 2017
(Millions)
Derivative assets with right of offset or master netting agreements
$
95

 
$
(55
)
 
$
40

Derivative liabilities with right of offset or master netting agreements
$
(82
)
 
$
55

 
$
(27
)
 
 
 
 
 
 
December 31, 2016
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
38

 
$
(33
)
 
$
5

Derivative liabilities with right of offset or master netting agreements
$
(215
)
 
$
33

 
$
(182
)
__________
(a)
With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
Credit-risk-related features
Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.
As of September 30, 2017, we had no collateral posted to derivative counterparties, to support the aggregate fair value of our net $27 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $27 million at September 30, 2017. 
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 2017 and 2016, 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 $95 million and $40 million, respectively, as of September 30, 2017. One hundred 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 five largest net counterparty positions represent approximately 97 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 nine months of 2017, sales to NGL Energy were approximately 10 percent of our total consolidated revenues adjusted for gain (loss) on derivatives.
Other
Collateral support for our commodity agreements could include margin deposits, letters of credit, surety bonds and guarantees of payment by credit worthy parties.
Basis of Presentation and Description of Business Accounting Policies (Policies)
Recently Adopted Accounting Standards
In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting, as part of the Simplification Initiative. The areas for simplification in ASU 2016-09 involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is required for annual periods beginning after December 15, 2016. Under ASU 2016-09, on a prospective basis, companies will no longer record excess tax benefits and deficiencies in additional paid in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit on the statement of operations. Other portions of the standard are adopted using either a prospective, retrospective, or modified retrospective approach depending on the topic covered in the standard. The Company adopted this guidance effective January 1, 2017 which impacted (a) our income tax provision in 2017 due to the tax deficiency recognized for tax and (b) the operating and financing activities sections of our Consolidated Statement of Cash Flows to reflect tax payments related to shares withheld for taxes. Cash outflows of $11 million and $5 million for the nine months ended September 30, 2017 and 2016, respectively, would have been included in operating activities under previous guidance, but are now reflected in financing activities.
Accounting Standards Not Yet Adopted
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, and has updated it with additional ASUs. 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. ASU 2014-09, as amended, is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The FASB will permit companies to adopt the new standard early, but not before the original effective date of annual reporting periods beginning after December 15, 2016. ASU 2014-09 can be applied using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements.
In 2016, we performed an initial assessment of the impact of ASU 2014-09 with the assistance of an outside consultant. Our assessment was based on a bottoms-up approach, in which we analyzed our existing contracts and current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our contracts. In 2017, we further documented our conclusions around the impact of the standard 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.
Currently, we do not expect the impact of adopting ASU 2014-09 to be material to our total net revenues and 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. We will adopt this standard on January 1, 2018 and, based on our evaluation to date, we anticipate using the modified retrospective method. We have finalized the majority of our documentation and assessment of the impact of the standard on our financial results and related disclosures and anticipate minimal adjustments to our disclosures in future filings from the adoption of this standard.
In February 2016, the FASB issued ASU 2016-02, Leases, to increase transparency and comparability among organizations by recognizing right-of-use assets and lease payment liabilities on the balance sheet and disclosing 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 policy elections to not recognize lease assets and 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 drilling rig commitments, certain equipment leases, and potentially other arrangements, the effects of which cannot be estimated at this time. 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. The Company continues to evaluate the impact of ASU 2016-02 to the Company’s Consolidated Financial Statements or related disclosures.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which will require entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption in an interim period is permitted, but any adjustments must be reflected as of the beginning of the fiscal year that includes that interim period. Restricted cash was approximately $13 million and $10 million as of September 30, 2017 and December 31, 2016, respectively. The Company does not expect any significant impact on its consolidated statement of cash flows from the adoption of the standard.
In January 2017, FASB issued 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. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years.
In February 2017, the FASB issued ASU 2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This ASU clarifies the scope and application of ASC 610-20 on the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The amendments are effective at the same time as the new revenue standard. For public entities, the amendments are effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted. The Company does not expect any significant impact on its consolidated financial statements from the adoption of the standard.
In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718). The amendments in this Update provide 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 amendments in this Update are effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. 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 the standard.
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.
Discontinued Operations Discontinued Operation (Tables)
Schedule of Disposal Groups Including Discontinued Operations Income Statement [Table Text Block]
Summarized Results of Discontinued Operations
 
Three months ended September 30, 2016
 
Nine months ended September 30, 2016
 
(Millions)
Total revenues(a)
$

 
$
64

Costs and expenses:
 
 
 
Depreciation, depletion and amortization
$

 
$
9

Lease and facility operating

 
18

Gathering, processing and transportation
1

 
49

Taxes other than income
1

 
2

General and administrative
1

 
9

Other—net
(2
)
 
4

Total costs and expenses
1

 
91

Operating loss
(1
)
 
(27
)
Gain on sale of assets
1

 
53

Income from discontinued operations before income taxes

 
26

Income tax provision(b)
1

 
14

Income (loss) from discontinued operations
$
(1
)
 
$
12


__________
(a) The nine months ended September 30, 2016 include $33 million net loss on derivatives.
(b) The nine months ended September 30, 2016 includes a valuation allowance on certain state tax carryovers.

Earnings (Loss) Per Common Share from Continuing Operations (Tables)
The following table summarizes the calculation of earnings per share.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(Millions, except per-share amounts)
Income (loss) from continuing operations
$
(150
)
 
$
(218
)
 
$
20

 
$
(441
)
Less: Dividends on preferred stock
3

 
4

 
11

 
15

Less: Loss on induced conversion of preferred stock

 
22

 

 
22

Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders for basic and diluted earnings (loss) per common share
$
(153
)
 
$
(244
)
 
$
9

 
$
(478
)
 
 
 
 
 
 
 
 
Basic weighted-average shares
398.1

 
341.5

 
394.1

 
302.8

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

 

 
1.9

 

Stock options

 

 
0.2

 

Diluted weighted-average shares
398.1

 
341.5

 
396.2

 
302.8

Earnings (loss) per common share from continuing operations:
 
 
 
 
 
 
 
Basic
$
(0.39
)
 
$
(0.72
)
 
$
0.02

 
$
(1.58
)
Diluted
$
(0.39
)
 
$
(0.72
)
 
$
0.02

 
$
(1.58
)

__________
(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. Additionally, 23.8 million common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock have been excluded from the computation of diluted earnings per share for all periods presented as their inclusion would be antidilutive due to application of the if-converted method.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(Millions)
Weighted-average nonvested restricted stock units and awards
1.6

 
2.4

 

 
1.8

Weighted-average stock options
0.1

 

 

 



The table below includes information related to stock options that were outstanding at September 30, 2017 and 2016 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.
 
September 30,
 
2017
 
2016
Options excluded (millions)
1.9

 
2.4

Weighted-average exercise price of options excluded
$
16.69

 
$
16.46

Exercise price range of options excluded
$11.75 - $21.81

 
$11.75 - $21.81

Third quarter weighted-average market price
$
10.23

 
$
11.11

Exploration Expense (Tables)
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(Millions)
Unproved leasehold property impairment, amortization and expiration
$
20

 
$
9

 
$
78

 
$
28

Geologic and geophysical costs

 
1

 
2

 
2

Dry hole costs

 

 

 
1

Total exploration expenses
$
20

 
$
10

 
$
80

 
$
31

Inventories (Tables)
Inventories
The following table presents a summary of our inventories as of the dates indicated below.
 
September 30,
2017
 
December 31,
2016
 
(Millions)
Material, supplies and other
$
39

 
$
30

Crude oil production in transit
3

 
2

     Total inventories
$
42

 
$
32

Debt and Banking Arrangements (Tables)
Debt
The following table presents a summary of our debt as of the dates indicated below.
 
September 30,
2017
 
December 31,
2016
 
(Millions)
Credit facility agreement
$
285

 
$

7.500% Senior Notes due 2020
350

 
500

6.000% Senior Notes due 2022
1,100

 
1,100

8.250% Senior Notes due 2023
500

 
500

5.250% Senior Notes due 2024
650

 
500

Other

 
1

     Total long-term debt
$
2,885

 
$
2,601

Less: Debt issuance costs on long-term debt(a)
26

 
26

Total long-term debt, net(a)
$
2,859

 
$
2,575


__________
(a) Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
Provision (Benefit) for Income Taxes (Tables)
Provision (Benefit) for Income Taxes from Continuing Operations
The following table presents the provision (benefit) for income taxes from continuing operations. 
 
Three months
ended September 30,
 
Nine months
ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(Millions)
Current:
 
 
 
 
 
 
 
Federal
$
(27
)
 
$

 
$
(27
)
 
$

State

 
(5
)
 

 
(5
)
 
(27
)
 
(5
)
 
(27
)
 
(5
)
Deferred:
 
 
 
 
 
 
 
Federal
(12
)
 
(117
)
 
39

 
(236
)
State
59

 
(10
)
 
(14
)
 
14

 
47

 
(127
)
 
25

 
(222
)
Total provision (benefit)
$
20

 
$
(132
)
 
$
(2
)
 
$
(227
)
Fair Value Measurements (Tables)
Assets and Liabilities Measured at Fair Value on Recurring Basis
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
September 30, 2017
 
December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$

 
$
95

 
$

 
$
95

 
$

 
$
38

 
$

 
$
38

Energy derivative liabilities
$

 
$
82

 
$

 
$
82

 
$

 
$
215

 
$

 
$
215

Total debt(a)
$

 
$
3,007

 
$

 
$
3,007

 
$

 
$
2,702

 
$

 
$
2,702

__________
(a)
The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,885 million and $2,600 million as of September 30, 2017 and December 31, 2016, 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.
Derivatives and Concentration of Credit Risk (Tables)
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 September 30, 2017.
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
 
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
Oct - Dec 2017
 
Fixed Price Swaps
 
WTI
 
(50,638
)
 
$
50.23

Crude Oil
 
Oct - Dec 2017
 
Basis Swaps
 
Midland-Cushing
 
(15,000
)
 
$
(0.62
)
Crude Oil
 
Oct - Dec 2017
 
Fixed Price Calls
 
WTI
 
(4,500
)
 
$
56.47

Crude Oil
 
2018
 
Fixed Price Swaps
 
WTI
 
(55,500
)
 
$
(52.69
)
Crude Oil
 
2018
 
Basis Swaps
 
Midland-Cushing
 
(17,521
)
 
$
(0.91
)
Crude Oil
 
2018
 
Basis Swaps
 
Nymex CMA Roll
 
(16,000
)
 
$
0.03

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

Crude Oil
 
2019
 
Fixed Price Swaps
 
WTI
 
(22,000
)
 
$
50.85

Crude Oil
 
2019
 
Basis Swaps
 
Midland-Cushing
 
(19,000
)
 
$
(0.93
)
Crude Oil
 
2019
 
Basis Swaps
 
Nymex CMA Roll
 
(4,000
)
 
$
0.07

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

   Crude Oil
 
2020
 
Basis Swaps
 
Midland-Cushing
 
(5,000
)
 
$
(1.16
)
Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
Oct - Dec 2017
 
Fixed Price Swaps
 
Henry Hub
 
(170
)
 
$
3.02

Natural Gas
 
Oct - Dec 2017
 
Basis Swaps
 
Permian
 
(73
)
 
$
(0.20
)
Natural Gas
 
Oct - Dec 2017
 
Basis Swaps
 
San Juan
 
(98
)
 
$
(0.18
)
Natural Gas
 
Oct - Dec 2017
 
Fixed Price Calls
 
Henry Hub
 
(15
)
 
$
4.50

Natural Gas
 
2018
 
Fixed Price Swaps
 
Henry Hub
 
(185
)
 
$
2.98

Natural Gas
 
2018
 
Basis Swaps
 
Permian
 
(43
)
 
$
(0.28
)
Natural Gas
 
2018
 
Basis Swaps
 
San Juan
 
(50
)
 
$
(0.34
)
Natural Gas
 
2018
 
Basis Swaps
 
Waha
 
(40
)
 
$
0.02

Natural Gas
 
2018
 
Basis Swaps
 
Houston Ship
 
(23
)
 
$
(0.08
)
Natural Gas
 
2018
 
Fixed Price Swaptions
 
Henry Hub
 
(20
)
 
$
3.33

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

Natural Gas
 
2019
 
Basis Swaps
 
Permian
 
(20
)
 
$
(0.34
)
Natural Gas
 
2019
 
Basis Swaps
 
Waha
 
(70
)
 
$
(0.15
)
Natural Gas
 
2019
 
Basis Swaps
 
Houston Ship
 
(10
)
 
$
(0.09
)
__________
(a)
Derivatives related to crude oil production are fixed price swaps settled on the business day average, basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with several crude oil and natural gas swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions grant the counterparty the option to enter into future swaps with us. 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.
(b)
Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.
(c)
The weighted average price for crude oil is reported in $/Bbl and natural gas is reported in $/MMBtu.
The following table presents our gross and net derivative assets and liabilities.
 
Gross Amount Presented on Balance Sheet
 
Netting Adjustments (a)
 
Net Amount
September 30, 2017
(Millions)
Derivative assets with right of offset or master netting agreements
$
95

 
$
(55
)
 
$
40

Derivative liabilities with right of offset or master netting agreements
$
(82
)
 
$
55

 
$
(27
)
 
 
 
 
 
 
December 31, 2016
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
38

 
$
(33
)
 
$
5

Derivative liabilities with right of offset or master netting agreements
$
(215
)
 
$
33

 
$
(182
)
__________
(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.
Basis of Presentation and Description of Business- Additional Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended
Jun. 30, 2017
acre
Sep. 30, 2017
Sep. 30, 2016
Dec. 31, 2016
Dec. 31, 2017
Subsequent Event [Member]
Subsequent Event [Line Items]
 
 
 
 
 
Capital Expenditure Reimbursement Received From Joint Venture
 
 
 
 
$ 49 
Distribution Received From Joint Venture
 
 
 
 
300 
Equity Method Investment Voting Percentage
50.00% 
 
 
 
 
Cash Contribution From Partner In Joint Venture At Closing
300 
 
 
 
 
Property To Be Contributed To Joint Venture
 
56 
 
 
 
Distribution To Be Received From Joint Venture
300 
 
 
 
 
Capital Expenditures To Be Paid By Joint Venture Partner
263 
 
 
 
 
Capital Expenditure Carry From Partner In Joint Venture
132 
 
 
 
 
Oil and Gas Acreage Dedication For Joint Venture
50,000 
 
 
 
 
Taxes paid for shares withheld
 
11 
 
 
Restricted Cash
 
$ 13 
 
$ 10 
 
Acquisitions (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Mar. 31, 2017
Boe
Well
acre
Sep. 30, 2017
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
 
 
Acquisition cost, subject to post-closing adjustments
$ 775 
 
Costs Incurred, Acquisition of Oil and Gas Properties
798 
 
Costs Incurred, Acquisition of Unproved Oil and Gas Properties
 
599 
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves
 
$ 200 
Producing wells
25 
 
Producing horizontals
18 
 
Drilled but uncompleted horizontal laterals
 
Gas and Oil Area, Developed, Net
18,000 
 
Gas and Oil Area, Undeveloped, Gross
900 
 
Production, Barrels of Oil Equivalents
10,000 
 
Discontinued Operations Discontinued Operation (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
 
 
 
 
Disposal Group, Including Discontinued Operation, Revenue
 
$ 0 1
 
$ 64 1
Disposal Group, Including Discontinued Operation, Depreciation and Amortization
 
 
Disposal Group, Including Discontinued Operation, Lease Operating Expense
 
 
18 
Disposal Group Including Discontinued Operation Gathering and Transportation Expense
 
 
49 
Disposal Group, Including Discontinued Operation Taxes other than income
 
 
Disposal Group, Including Discontinued Operation, General and Administrative Expense
 
 
Disposal Group, Including Discontinued Operation, Other Expense
 
(2)
 
Disposal Group, Including Discontinued Operation, Operating Expense
 
 
91 
Disposal Group, Including Discontinued Operation, Operating Income (Loss)
 
(1)
 
(27)
Discontinued Operation, Provision for Loss (Gain) on Disposal, before Income Tax
 
 
53 
Disposal Group Including Discontinued Operation Income before Tax
 
 
26 
Discontinued Operation, Tax Effect of Discontinued Operation
 
 
14 2
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
(1)
12 
Net gain (loss) on derivatives
(106)
38 
213 
(59)
Additional Disclosures [Abstract]
 
 
 
 
Proceeds from Divestiture of Businesses
 
 
 
862 
Disposal Group including Discontinued Operations Net Cash Provided By Used In Operating Activities
 
 
 
28 
Increase (Decrease) in Other Accrued Liabilities
 
 
40 
42 
Disposal Group including Discontinued Operations Net Cash Provided By Used In Investing Activities
 
 
 
32 
Piceance Basin [Member]
 
 
 
 
Additional Disclosures [Abstract]
 
 
 
 
DisposalGroupOperatingTaxRefund
 
 
10 
 
Domestic Destination [Member]