WPX ENERGY, INC., 10-K filed on 2/22/2018
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2017
Feb. 21, 2018
Jun. 30, 2017
Document Documentand Entity Information [Abstract]
 
 
 
Document Type
10-K 
 
 
Amendment Flag
false 
 
 
Document Period End Date
Dec. 31, 2017 
 
 
Entity Registrant Name
2017 
 
 
Entity Central Index Key
FY 
 
 
Trading Symbol
WPX 
 
 
Entity Registrant Name
WPX ENERGY, INC. 
 
 
Entity Central Index Key
0001518832 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Common Stock, Shares Outstanding
 
398,204,221 
 
Entity Public Float
 
 
$ 3,822,718,222 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Current assets:
 
 
Cash and cash equivalents
$ 189 
$ 496 
Accounts receivable, net of allowance of $2 million as of December 31, 2017 and $3 million as of December 31, 2016
307 
168 
Derivative Asset, Current
36 
26 
Inventories
44 
32 
Assets classified as held for sale, Current
34 
12 
Other
28 
20 
Total current assets
638 
754 
Equity Method Investments
70 
Properties and equipment, net (successful efforts method of accounting)
7,454 
6,157 
Derivative Asset, Noncurrent
23 
12 
Assets classified as held for sale, Noncurrent
317 
Other noncurrent assets
22 
24 
Total assets
8,207 
7,264 
Current liabilities:
 
 
Accounts payable
446 
222 
Accrued Liabilities and Other Liabilities
209 
301 
Liabilities associated with assets held for sale, Current
13 
Derivative liabilities
171 
152 
Total current liabilities
839 
677 
Deferred income taxes
117 
251 
Long-term Debt and Capital Lease Obligations
2,575 1
2,575 1
Derivative liabilities
65 
63 
Asset retirement obligations
36 
38 
Liabilities associated with assets held for sale, Noncurrent
62 
Other noncurrent liabilities
448 
132 
Contingent liabilities and commitments (Note 11)
   
   
Stockholders’ equity:
 
 
Preferred stock (100 million shares authorized at $0.01 par value; 4.8 million shares outstanding at December 31, 2017 and 2016)
232 
232 
Common stock (2 billion shares authorized at $0.01 par value; 398.3 million and 344.7 million shares issued and outstanding at December 31, 2017 and 2016)
Additional paid-in-capital
7,479 
6,803 
Accumulated deficit
(3,588)
(3,572)
Total equity
4,127 
3,466 
Total liabilities and equity
$ 8,207 
$ 7,264 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 2 
$ 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
398,300,000 
344,700,000 
Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Product revenues:
 
 
 
Oil sales
$ 1,029 
$ 551 
$ 494 
Natural gas sales
163 
125 
138 
Natural gas liquid sales
115 
46 
23 
Total product revenues
1,307 
722 
655 
Net gain (loss) on derivatives
(207)
418 
Commodity management
25 
177 
286 
Other
Total revenues
1,336 
693 
1,366 
Costs and expenses:
 
 
 
Depreciation, depletion and amortization
673 
623 
528 
Lease and facility operating
218 
163 
145 
Gathering, processing and transportation
94 
76 
64 
Taxes other than income
102 
60 
62 
Exploration
101 
42 
85 
General and administrative
174 1
214 1
210 1
Commodity management, including charges for unutilized pipeline capacity
27 
208 
261 
Net (gain) loss on sales of assets, divestment of transportation contracts and impairment of producing properties (Note 5)
(111)
22 
(349)
Acquisition costs
23 
Other—net
15 
16 
63 
Total costs and expenses
1,293 
1,424 
1,092 
Operating income (loss)
43 
(731)
274 
Interest expense
(188)
(207)
(187)
Loss on extinguishment of debt
(17)
(1)
(65)
Investment income and other
(2)
Income (loss) from continuing operations before income taxes
(159)
(937)
20 
Provision (benefit) for income taxes
(148)
(325)
24 
Loss from continuing operations
(11)
(612)
(4)
Income (loss) from discontinued operations
(5)
11 2
(1,722)2
Net loss
(16)
(601)
(1,726)
Less: Net income attributable to noncontrolling interests
Net income (loss) Attributable to Parent
(16)
(601)
(1,727)
Preferred Stock Dividends, Income Statement Impact
15 
18 
Preferred Stock Conversions, Inducements
22 
Net Income (Loss) Available to Common Stockholders,
(31)
(641)
(1,736)
Income (Loss) from Continuing Operations Attributable to WPX
(26)
(652)
(13)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to WPX
$ (5)
$ 11 
$ (1,723)
Basic and diluted earnings (loss) per common share:
 
 
 
Income (Loss) from Continuing Operations, Per Basic and Diluted Share
$ (0.06)
$ (2.08)
$ (0.06)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic and Diluted Share
$ (0.02)
$ 0.03 
$ (7.36)
Earnings Per Share, Basic and Diluted
$ (0.08)
$ (2.05)
$ (7.42)
Basic and Diluted weighted-average shares
395.1 
313.3 
234.2 
Consolidated Statements of Operations Consolidated Statements of Operations - Parentheticals (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Consolidated Statement of Operations (Parentheticals) [Abstract]
 
 
 
Allocated Share-based Compensation Expense
$ 30 
$ 33 
$ 31 
Consolidated Statements of Changes in Equity (USD $)
In Millions, unless otherwise specified
Total
Total Stockholders’ Equity
Preferred Stock
Common Stock
Capital in Excess of Par Value
Accumulated Deficit
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Balance at beginning of period at Dec. 31, 2014
$ 4,428 
$ 4,319 
 
$ 2 
$ 5,562 
$ (1,244)
$ (1)
$ 109 1
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss) attributable to WPX Energy, Inc.
(1,726)
(1,727)
 
 
 
(1,727)
 
1
Stock based compensation, net of tax impact
26 
26 
 
 
26 
 
 
 
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings
(11)
(11)
 
 
(11)
 
 
 
Stock Issued During Period, Value, New Issues
292 
292 
 
 
292 
 
 
 
Stock Issued During Period, Value, Acquisitions
296 
296 
 
295 
 
 
 
Issuance of preferred stock to public, net of offering costs
339 
339 
339 
 
 
 
 
 
Stockholders' Equity, Other
(109)
 
 
 
 
 
Noncontrolling Interest, Decrease from Deconsolidation1
 
 
 
 
 
 
 
(110)
Preferred Stock Conversions, Inducements
 
 
 
 
 
 
 
Balance at end of period at Dec. 31, 2015
3,535 
3,535 
339 
6,164 
(2,971)
1
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss) attributable to WPX Energy, Inc.
(601)
(601)
 
 
 
(601)
 
 
Stock based compensation, net of tax impact
23 
23 
 
 
23 
 
 
 
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings
(18)
(18)
 
 
(18)
 
 
 
Stock Issued During Period, Value, New Issues
538 
538 
 
 
538 
 
 
 
Conversion of Stock, Amount Issued
11 
11 
(107)
 
118 
 
 
 
Preferred Stock Conversions, Inducements
(22)
(22)
 
 
(22)
 
 
 
Balance at end of period at Dec. 31, 2016
3,466 
3,466 
232 
6,803 
(3,572)
1
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss) attributable to WPX Energy, Inc.
(16)
(16)
 
 
 
(16)
 
 
Stock based compensation, net of tax impact
22 
22 
 
 
22 
 
 
 
Adjustments to Additional Paid in Capital, Dividends in Excess of Retained Earnings
(15)
(15)
 
 
(15)
 
 
 
Stock Issued During Period, Value, New Issues
670 
670 
 
669 
 
 
 
Preferred Stock Conversions, Inducements
 
 
 
 
 
 
 
Balance at end of period at Dec. 31, 2017
$ 4,127 
$ 4,127 
$ 232 
$ 4 
$ 7,479 
$ (3,588)
$ 0 
$ 0 1
Consolidated Statements of Changes in Equity (Parenthetical)
Dec. 31, 2015
Noncontrolling interest, ownership percentage by noncontrolling owners
31.00% 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Operating Activities
 
 
 
Net income (loss) attributable to WPX Energy, Inc.
$ (16)
$ (601)
$ (1,726)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
673 
631 
940 
Deferred income tax benefit
(134)
(281)
(1,005)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments
158 
38 
2,426 
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net
(207)
418 
Derivative, Cash Received on Hedge
302 
617 
Unrealized Loss on Derivatives, including Discontinued Operations
46 
Amortization of stock-based awards
32 
36 
35 
Loss on extinguishment of debt and acquisition bridge financing fees
17 
81 
Net gains on sales of assets and divestment of transportation contracts
(170)
(29)
(385)
Cash provided (used) by operating assets and liabilities:
 
 
 
Accounts receivable
(153)
126 
233 
Inventories
(8)
10 
(2)
Margin deposits and customer margin deposits payable
(1)
26 
Other current assets
(8)
Accounts payable
158 
(72)
(247)
Increase (Decrease) in Income Taxes Payable
12 
(19)
Accrued and other current liabilities
(31)
(45)
87 
Increase (Decrease) in Other Accrued Liabilities
(53)
(53)
(14)
Other, including changes in other noncurrent assets and liabilities
28 
(33)
171 
Net cash provided by operating activities(a)
507 1
268 1
819 1
Investing Activities(a)
 
 
 
Payments to Acquire Productive Assets
1,161 
578 
1,124 
Proceeds from sales of assets
193 
1,127 
810 
Proceeds (payments) related to divestment of transportation contracts
(238)
209 
Payments to Acquire Businesses, Gross
799 
1,212 
Proceeds from joint venture formation
338 
Purchases of a business, net of cash acquired
(8)
Other
(1)
(1)
Net cash provided by (used in) investing activities(a)
(1,438)1
310 1
(1,316)1
Financing Activities
 
 
 
Proceeds from common stock
672 
540 
295 
Proceeds from preferred stock
339 
Dividends paid on preferred stock
(15)
(18)
(6)
Payments related to induced conversion of preferred stock to common stock
(10)
Borrowings on credit facility
661 
380 
841 
Payments on credit facility
(661)
(645)
(856)
Proceeds from long-term debt, net of discount
148 
1,000 
Payments for retirement of long-term debt, including premium
(165)
(356)
(1,100)
Payments Related to Tax Withholding for Share-based Compensation
12 
Payments for debt issuance costs, credit facility amendment fees and acquisition bridge financing fees
(2)
(5)
(40)
Other
(2)
Net cash provided by (used in) financing activities
624 
(120)
465 
Net increase (decrease) in cash and cash equivalents
(307)
458 
(32)
Cash and cash equivalents at beginning of period
496 
38 
70 
Cash and cash equivalents at end of period
189 
496 
38 
Increase to properties and equipment
(1,232)
(584)
(865)
Changes In Related Accounts Payable And Accounts Receivable
$ (71)
$ (6)
$ 259 
Consolidated Statements of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Increase to properties and equipment
$ 1,232 
$ 584 
$ 865 
Changes in related accounts payable and accounts receivable
71 
(259)
Payments to Acquire Productive Assets
$ 1,161 
$ 578 
$ 1,124 
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Notes)
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]
Description of Business, Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Operations of our company include oil, natural gas and NGL development 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 commodity management activities, that include oil and natural gas purchased from third-party working interest owners in operated wells, the management of various commodity contracts, such as transportation and related derivatives, and the marketing of Piceance Basin volumes during a transition period from April 1, 2016 to June 30, 2016 (see Note 3).    
In addition, we had other operations sold in 2015 and 2016 which are reported as discontinued operations, as discussed below.
In February 2018, we announced that we signed an agreement to sell our holdings in the San Juan Basin’s Gallup oil play for $700 million to an undisclosed third party. Closing is expected to occur in the first quarter of 2018. As discussed in Note 5, we divested of our legacy natural gas assets in the San Juan Basin in December 2017. Upon closing of the most recent transaction, we will no longer have a presence in the San Juan Basin. See Note 17 of Notes to Consolidated Financial Statements.
The consolidated businesses represented herein as WPX Energy, Inc. is also referred to as “WPX,” the “Company,” “we,” “us” or “our.”
Basis of Presentation and Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the Company, are accounted for under the equity method. All material intercompany transactions have been eliminated. The Company has no other elements of comprehensive income other than net income.
Our continuing operations comprise a single business segment, which includes the development, production and commodity management activities of oil, natural gas and NGLs in the United States.
Discontinued Operations
Our discontinued operations include the results of previously owned properties in the Piceance and Powder River Basins and our previously owned 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”), an oil and gas exploration and production company with activities in Argentina and Colombia.
See Note 3 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations. Additionally, see Note 11 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).    
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions which impact these financials include:
impairment assessments of long-lived assets;
valuation of deferred tax assets and liabilities;
valuations of derivatives;
estimation of oil and natural gas reserves;
assessments of litigation-related contingencies; and
asset retirement obligations.
 
These estimates are discussed further throughout these notes.
Cash and cash equivalents
Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Restricted cash
Restricted cash was approximately $12 million and $10 million as of December 31, 2017 and 2016, respectively, and is included in other current assets on the Consolidated Balance Sheets.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Inventories
All inventories are stated at the lower of cost or market. Our materials, supplies and other inventories consist of tubular goods and production equipment for future transfer to wells and crude oil production in transit. Inventory is recorded and relieved using the weighted average cost method. The following table presents a summary of inventories.
 
Years ended December 31,
 
2017
 
2016
 
(Millions)
Material, supplies and other
$
43

 
$
30

Crude oil production in transit
1

 
2

 
$
44

 
$
32



During the third quarter of 2016, we recorded a $4 million impairment charge of certain material and supplies inventory.
Properties and equipment
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expenses. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
Unproved properties include lease acquisition costs. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense on the Consolidated Statements of Operations. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs as unproved properties.
From time to time we may exchange leasehold acreage with third parties. In connection with this type of nonmonetary exchange, we must record assets received based on the fair value of either the asset surrendered or, if more readily determinable, the assets received. Any resulting difference between the fair value and the carrying value of the assets is recorded as a gain or loss, to the extent a loss exceeds accumulated amortization, in the Consolidated Statements of Operations.
Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in operating income (loss) as either a separate line item, if individually significant, or included in other—net on the Consolidated Statements of Operations.
Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
Depreciation, depletion and amortization
Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
Impairment of long-lived assets
We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Additionally, our leasehold costs are evaluated for impairment if the proved property costs within a basin are impaired.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities
Due to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.
Asset retirement obligations
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
Cash flows from revolving credit facilities
Proceeds and payments related to any borrowings under a revolving credit facility are reflected in the financing activities of the Consolidated Statements of Cash Flows on a gross basis.
Derivative instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
 
Derivative Treatment
  
Accounting Method
 
Normal purchases and normal sales exception
  
Accrual accounting
 
Designated in a qualifying hedging relationship
  
Hedge accounting
 
All other derivatives
  
Mark-to-market accounting
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
Certain gains and losses on derivative instruments included on the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to commodity management and for which we have not elected the normal purchases and normal sales exception;
realized gains and losses on all derivatives that settle financially;
realized gains and losses on derivatives held for trading purposes; and
realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
Realized gains and losses on derivatives that require physical delivery are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product and commodity management revenues
Our revenues on the Consolidated Statement of Operations include oil, natural gas and natural gas liquids sales (collectively, “product revenues”), commodity management revenues and net gain (loss) on derivatives. Product revenues relate to production from properties in which we own an interest. Commodity management revenues primarily relate to sales of products we may purchase from other third parties in the areas we operate. We derive substantially all of our revenues from the sale of oil, natural gas and natural gas liquids in the continental United States. We believe the disaggregation of product revenues into the three major product types of oil sales, natural gas sales and natural gas liquid sales is an appropriate level of detail for our company’s primary activity and industry.
Our contracts for oil and natural gas sales are typically standard industry contracts that may include modifications for counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. Our contracts related to natural gas liquids sales are generally with the company contracted to gather and process natural gas to extract the natural gas liquids. The provider of these services typically purchases our share of the natural gas liquids pursuant to the terms of each contract. Oil, natural gas and natural gas liquids prices are derived from stated market prices which are then adjusted to reflect deductions including fuel, shrink, transportation, fractionation and processing. Product revenues are initially accrued based on volume and price estimates using the best available information. These accruals are typically actualized one to two months later when volume and pricing are confirmed. Adjustments to actualize the accruals for product revenues are generally not material.
Revenue is recognized when the performance obligations under the terms of our contracts with customers are satisfied. The primary performance obligation for the material portion of our revenue contracts is the delivery of oil, natural gas or natural gas liquids to our customers. Payment is typically due 30 to 45 days following delivery of product to our customers.
Revenues from production in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net revenue interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2017 and 2016 was insignificant.
Commodity management expenses
Commodity management expenses primarily relate to product we may purchase from other third parties in the areas we operate. Charges for unutilized transportation capacity are included in commodity management expenses and were $27 million and $38 million in 2016 and 2015, respectively.
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. We record deferred taxes for the differences between the tax and book basis of our assets as well as loss or credit carryovers to future years. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. Deferred tax liabilities and assets are classified as noncurrent on the statement of financial position.
Employee stock-based compensation
Restricted stock units and awards are generally valued at market value on the grant date and generally vest over three years. Restricted stock compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units and awards (see Note 4).
Debt issuance costs
Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company had total net debt issuance costs of $32 million and $37 million as of December 31, 2017 and 2016, respectively. Unamortized debt issuance costs related to the Company’s senior unsecured notes are reported in long-term debt (see Note 9) and debt issuance costs related to the Credit Facility are recorded in other noncurrent assets on the Company’s Consolidated Balance Sheets.    
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 $12 million, $6 million and $8 million for the years ended December 31, 2017, 2016 and 2015 respectively, would have been included in operating activities under previous guidance, but are now reflected in financing activities. Previously reported periods have been reclassified to conform with our presentation for the current period.
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 permits 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 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.
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 using the modified retrospective method. We have finalized our documentation and assessment of the impact of the standard on our financial results and related disclosures and have incorporated disclosure changes in this document; therefore, we 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 $12 million and $10 million as of December 31, 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. The Company will adopt this standard on January 1, 2018 and we do not expect a significant impact on our consolidated financial statements from the adoption of the standard.
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 a significant impact on consolidated financial statements from the adoption of this 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 will adopt this standard on January 1, 2018 and we do not expect a significant impact on our 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 a significant impact on its consolidated financial statements from the adoption of this standard unless we apply hedge accounting in a future period.
Acquisitions (Notes)
Mergers, Acquisitions and Dispositions Disclosures [Text Block]
Acquisitions
2017
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, included 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. We estimated that approximately $599 million of the purchase price is allocable to unproved properties and approximately $200 million is allocable to proved developed 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.
2015
On August 17, 2015, we completed the acquisition of privately held RKI Exploration & Production, LLC (“RKI”). Per the terms of the merger agreement, the purchase price was $2.75 billion, consisting of 40 million unregistered shares of WPX common stock and approximately $2.28 billion in cash (the “RKI Acquisition”). The cash consideration was subject to closing adjustments and was reduced by our assumption of $400 million of aggregate principal amount of RKI’s senior notes and amounts outstanding under RKI’s revolving credit facility along with other working capital items. We incurred approximately $23 million of acquisition-related costs, primarily related to legal and advisory fees which are reflected on a separate line item on the Consolidated Statements of Operations. In addition, we incurred $16 million of acquisition bridge facility fees, included in interest expense, and a $65 million loss on extinguishment of RKI’s senior notes, reflected in loss on extinguishment of debt on the Consolidated Statements of Operations.
WPX funded the RKI Acquisition with proceeds from a combination of debt, preferred stock and common stock offerings along with available cash on hand and borrowings under its revolving credit facility.
The following table presents the unaudited pro forma financial results for the year ended December 31, 2015 as if the RKI Acquisition and related financings had been completed January 1, 2014. The year ended December 31, 2015 has been adjusted to exclude $23 million of acquisition costs, $65 million loss on extinguishment of acquired debt and $16 million of acquisition bridge facility fees. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the RKI Acquisition occurred on the date assumed or for the period presented, nor is such information indicative of the Company’s expected future results of operations.
 
 
Year Ended December 31,
 
 
2015
 
 
(Millions)
Revenues
 
$
1,578

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


The RKI Acquisition qualified as a business combination, and as a result, we estimated the fair value of the underlying shares distributed, the assets acquired and the liabilities assumed as of the August 17, 2015 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. We used a combination of market data, discounted cash flow models and replacement estimates in determining the fair value of the oil and gas properties and the related midstream assets, all of which include estimates and assumptions such as future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs. Deferred taxes must also be recorded for any differences between the assigned values and the carryover tax bases of assets and liabilities. Deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and carryovers at the acquisition date (see Note 10). The following table summarizes the consideration paid for the RKI Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date. The final purchase price allocation is presented below.
 
 
 Purchase Price Allocation
 
 
(Millions)
Consideration:
 
 
Cash, net of an estimated post-close settlement
 
$
1,251

Fair value of WPX common stock issued
 
296

Total consideration
 
$
1,547

Fair value of liabilities assumed:
 
 
Accounts payable
 
$
104

Accrued liabilities
 
74

Deferred income taxes
 
752

Long-term debt
 
990

Asset retirement obligation
 
23

Total liabilities assumed as of the acquisition date
 
1,943

Fair value of assets acquired:
 
 
Cash and cash equivalents
 
51

Accounts receivable, net
 
80

Derivative assets, current
 
97

Derivative assets, noncurrent
 
34

Inventories
 
12

Other current assets
 
3

Properties and equipment(a)
 
3,209

Other noncurrent assets
 
4

Total assets acquired as of the acquisition date
 
3,490

Net fair value of assets and liabilities
 
$
1,547

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

Unproved properties
 
2,168

Gathering, processing and other facilities
 
157

Other
 
3

Total
 
$
3,209

Discontinued Operations
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]
Discontinued Operations
On February 8, 2016, we signed an agreement with Terra Energy Partners LLC (“Terra”) to sell WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations for $910 million. The agreement also required Terra to become financially responsible for approximately $104 million in transportation obligations held by our marketing company. Additionally, WPX Energy Rocky Mountain LLC had natural gas derivatives with a fair value of $48 million as of the closing date. The parties closed this sale in April of 2016 and we received net proceeds of $862 million, subject to post-closing adjustments, resulting in a gain of $52 million. We performed certain transition services for the buyer which concluded during third-quarter 2016. In addition, we had an agreement with the buyer to purchase production through June 30, 2016 which is reported in commodity management revenue and expenses.
The Piceance Basin represented 52 percent of our total proved reserves at December 31, 2015.
Significant transactions for the Piceance Basin Operations reflected in the tables below are as follows:
$52 million gain recorded on the sale of the Piceance Basin in 2016.
As a result of market conditions including oil and natural gas prices in the fourth quarter of 2015, we performed impairment assessments of our proved producing properties. As a result of these assessments, which included the possibility of cash flows from a divestiture of the Piceance Basin, we recorded a total of $2,334 million in impairment charges associated with the Piceance Basin, of which approximately $2,308 million is recorded in impairment of assets in the table below and $26 million is included in exploration expenses.
In August 2015, we signed agreements for the sale of our Powder River Basin for $80 million. On September 1, 2015, we completed a portion of the Powder River Basin divestiture. The remaining portion of the divestiture, which relates to our equity method investment in Fort Union Gas Gathering, LLC, closed on October 30, 2015. We recorded a pre-tax loss of $15 million related to this transaction during 2015. During the first and second quarters of 2015, we recorded a total of $16 million in impairments of the net assets to a probability weighted-average of expected sales prices for the Powder River Basin. In addition, we retained certain firm gathering and treating obligations with total commitments of $104 million through 2020 related to the Powder River properties sold. These commitments had been in excess of our production throughput. At the time of closing, we also had certain pipeline capacity obligations held by our marketing company with total commitments through 2021 totaling $150 million, which were related to the Powder River operation. With the closing of the Powder River Basin sale and exiting this basin in 2015, we recorded $187 million of expense related to these contracts, which is included as a separate line below. This expense was the estimated present value of the $254 million in payments associated with these contracts remaining as of the Powder River Basin sales date, and includes the fair value of estimated recoveries from third parties and discounting based on our risk adjusted borrowing rate. Liabilities of $54 million and $133 million were recorded in accrued and other current liabilities and other noncurrent liabilities, respectively, as of the closing date. In 2017, we increased the remaining liability for a change in estimate of third-party recoveries of future gathering and processing fees due to recent collectability issues.
During the third quarter of 2014, we had signed an agreement to sell our Powder River Basin holdings. This sales agreement did not successfully close in March 2015 and we subsequently terminated the transaction with the counterparty. During third-quarter 2015, we received $13 million in escrow funds as a result of the terminated contract and this amount is included in Other-net expense below.
On January 29, 2015 we completed the divestiture of our international interests and received net proceeds of $291 million after expenses but before $17 million of international’s cash on hand as of the closing date. We recorded a pretax gain of $41 million related to this transaction during first quarter 2015.
Summarized Results of Discontinued Operations
The following table presents the results of discontinued operations for the years presented.
 
Years Ended December 31,
 
2017
 
2016
 
2015
 
(Millions)
 
 
Total revenues(a)
$

 
$
64

 
$
592

Costs and expenses:
 
 
 
 
 
Depreciation, depletion and amortization
$

 
$
9

 
$
412

Lease and facility operating

 
18

 
103

Gathering, processing and transportation

 
49

 
257

Taxes other than income

 
2

 
21

Exploration

 

 
26

General and administrative

 
9

 
45

Commodity management

 

 
1

Accrual for contract obligations retained
5

 

 
187

Impairment of assets

 

 
2,324

Accretion of liabilities related to contract obligations retained
6

 
2

 
2

Other—net(b)
(3
)
 
6

 
(9
)
Total costs and expenses(c)
8

 
95

 
3,369

Operating income (loss)
(8
)
 
(31
)
 
(2,777
)
Investment income and other

 

 
6

Gain (loss) on sales of domestic assets

 
51

 
(15
)
Gain (loss) on sale of international assets

 

 
41

Income (loss) from discontinued operations before income taxes
(8
)
 
20

 
(2,745
)
Provision (benefit) for income taxes
(3
)
 
9

 
(1,023
)
Income (loss) from discontinued operations(d)
$
(5
)
 
$
11

 
$
(1,722
)
__________
(a) Includes $15 million related to international activity for 2015.
(b) Includes severance tax refund received in 2017.
(c) Includes $8 million related to international activity for 2015.
(d) Includes $52 million related to international activity for 2015.
Cash Flows Attributable to Discontinued Operations
In addition to the amounts presented below, cash outflows related to previous accruals for the Powder River Basin gathering and transportation contracts retained by WPX were $53 million, $53 million and $14 million for 2017, 2016 and 2015, respectively. During 2017, we received a $10 million severance tax refund for prior years related to our former Piceance Basin operations.
 
Years Ended December 31,
 
2016
 
2015
 
(Millions)
Cash provided by operating activities(a)
$
25

 
$
187

Capital expenditures within investing activities
$
(35
)
 
$
(266
)
__________
(a) Excluding income taxes and changes to working capital.
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
 The following table summarizes the calculation of earnings per share.
 
Years Ended December 31,
 
2017
 
2016
 
2015
 
(Millions, except per-share amounts)
Loss from continuing operations attributable to WPX Energy, Inc.
$
(11
)
 
$
(612
)
 
$
(4
)
Less: Dividends on preferred stock
15

 
18

 
9

       Less: Loss on induced conversion of preferred stock

 
22

 

Loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted loss per common share
$
(26
)
 
$
(652
)
 
$
(13
)
Basic weighted-average shares
395.1

 
313.3

 
234.2

Diluted weighted-average shares(a)
395.1

 
313.3

 
234.2

Loss per common share from continuing operations:
 
 
 
 
 
Basic
$
(0.06
)
 
$
(2.08
)
 
$
(0.06
)
Diluted
$
(0.06
)
 
$
(2.08
)
 
$
(0.06
)

 __________
(a) The following table includes amounts that have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc. available to common stockholders. The 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 as their inclusion would be antidilutive due to application of the if-converted method.
 
Years Ended December 31,
 
2017
 
2016
 
2015
 
(Millions)
Weighted-average nonvested restricted stock units and awards
2.1

 
2.2

 
1.3

Weighted-average stock options
0.2

 
0.1

 
0.1

Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 14)
19.8

 
23.8

 
15.5


The table below includes information related to stock options that were outstanding at December 31, 2017, 2016 and 2015 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
 
December 31,
 
2017
 
2016
 
2015
Options excluded (millions)
1.5

 
2.0

 
2.6

Weighted-average exercise price of options excluded
$
17.80

 
$
17.42

 
$
16.16

Exercise price range of options excluded
$14.41 - $21.81

 
$14.41 - $21.81

 
$11.46 - $21.81

Fourth quarter weighted-average market price
$
12.10

 
$
13.23

 
$
7.43



The diluted weighted-average shares excludes the effect of approximately 0.6 million and 3.0 million nonvested restricted stock units for 2017 and 2015, respectively. These restricted stock units were antidilutive under the treasury stock method.
Asset Sales, Impairments and Exploration Expenses
Asset Sales, Impairments and Exploration Expenses
Asset Sales, Impairments, Other Expenses and Exploration Expenses
Asset Sales and Impairments
2017
Net gain on sales of assets for the year ended December 31, 2017 primarily reflect total gains of $103 million from exchanges of leasehold acreage in the Permian Basin and $56 million from the recognition of deferred gains related to the completion of commitments from the sales of gathering systems discussed below. The gains were partially offset by a $60 million impairment of natural gas-producing properties held for sale in the San Juan Basin as discussed below. Net gain on sales of assets for the year ended December 31, 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.
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. 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 subsequently closed a majority of the transaction in the fourth quarter of 2017, which resulted in a gain of approximately $2 million. The assets and corresponding liabilities associated with the portion of the divestment that is expected to close in the first half of 2018 are classified as held for sale on the Consolidated Balance Sheets as of December 31, 2017 and 2016.
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. The total remaining commitments related to these contracts for the remainder of 2016 and thereafter were approximately $400 million. 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 $18 million in the subsequent quarters of 2016 as certain in-progress construction was completed. As of December 31, 2016, the deferred gain was $11 million, most of which was recognized in 2017, related to an estimated $4 million of remaining recorded obligations for in-progress construction. See Note 8 for liabilities accrued for future construction and deferred gain related to these obligations.
2015
During the fourth quarter of 2015, we completed the sale of a North Dakota gathering system for approximately $185 million, subject to closing adjustments. Under the terms of the agreement, a subsidiary of the buyer, Midstream Capital Partners, will manage the overall system and we will operate, at the direction of the owner, the system for a two year initial term and any renewal terms. Under the terms of the agreement, we are required to complete certain future construction obligations. As a result of this transaction, we recorded a net gain of $70 million in fourth-quarter 2015. See Note 8 for liabilities accrued for future construction and deferred gain related to these obligations.
During May 2015, WPX completed the sale of a package of marketing contracts and release of certain related firm transportation capacity in the Northeast for approximately $209 million in cash. The transaction released us from various long-term natural gas purchase and sales obligations and approximately $390 million in future demand payment obligations associated with the transport position. As a result of this transaction, we recorded a net gain of $209 million in second-quarter 2015 on these executory contracts.
During the first quarter of 2015, we sold a portion of our Appalachian Basin operations and released certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $288 million, subject to post-closing adjustments. Including an estimate of post-closing adjustments of $17 million, we recorded a net gain of $69 million in first-quarter 2015. The assets were primarily located in the Appalachian Basin in Susquehanna County, Pennsylvania. The transaction also included the release of firm transportation capacity that we had under contract in the Northeast, primarily with Millennium Pipeline. Upon the transfer of the firm capacity, we were released from approximately $24 million per year in annual demand obligations associated with the transport.
Other Expenses
In December 2015, we plugged and abandoned the remaining wells serviced by a certain natural gas gathering system in the Appalachian Basin. As a result, we recorded approximately $23 million associated with the net present value of future obligations under the gathering agreement which is included in other—net on the Consolidated Statements of Operations.
During the first quarter of 2015, we executed a termination and settlement agreement to release us from a crude oil transportation and sales agreement in anticipation of entering into a different agreement with another third party with more favorable terms. As a result of this contract termination and settlement, we recorded an expense of approximately $22 million which is included in other—net on the Consolidated Statements of Operations.
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Years Ended December 31,
 
2017
 
2016
 
2015
 
(Millions)
Unproved leasehold property impairments, amortization and expiration
$
98

 
$
38

 
$
54

Geologic and geophysical costs
3

 
$
3

 
7

Impairments of exploratory area well costs and dry hole costs

 
1

 
24

Total exploration expenses
$
101

 
$
42

 
$
85


Unproved leasehold property impairment, amortization and expiration for 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.
Impairments of exploratory well costs and dry hole costs for 2015 include $24 million related to a non-core exploratory play where we no longer intend to continue exploration activities.
Unproved leasehold property impairments, amortization and expiration in 2015 include impairments of $26 million related to non-core exploratory areas where we no longer intend to continue exploration activities.
Investments Investments
Equity Method Investments and Joint Ventures Disclosure [Text Block]
Investments
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 each have a 50 percent voting interest in the newly formed joint venture legal entity, Catalyst Midstream Partners LLC (“Catalyst”) and a Howard entity will serve as operator. In addition to a $300 million cash contribution, Howard is obligated to fund the first $263 million of joint venture capital expenditures. At closing in October 2017, WPX contributed subsidiaries holding crude oil gathering and natural gas processing assets already in service and/or under construction, with a net book value of approximately $53 million. WPX also paid $11 million for advisory services and legal fees on the transaction. Howard contributed $439 million in cash at closing, $139 million of which applies to the $263 million carry obligation of Howard including $49 million for capital expenditures from January 1, 2017 to closing. Concurrently, WPX received a $300 million special distribution plus the $49 million for capital expenditures from Catalyst. We will account for our investment in Catalyst as an equity method investment. In connection with the joint venture, a consolidated subsidiary of WPX dedicated production from 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 with subsidiaries of Catalyst. The agreements do not include any minimum volume commitments. As of December 31, 2017, our investment in Catalyst is $64 million. We have deferred recognition of the $349 million and will recognize it over the 20 years based on production volumes as a deduction to gathering, processing and transportation expense. The $349 million is reported within other noncurrent liabilities on the Consolidated Balance Sheet.
Properties and Equipment
Properties and Equipment
Properties and Equipment
Properties and equipment is carried at cost and consists of the following:
 
 
Estimated
Useful
Life(a)
(Years)
 
December 31,
 
2017
 
2016
 
 
 
(Millions)
Proved properties
(b)
 
$
6,875

 
$
5,451

Unproved properties
(c)
 
2,334

 
2,065

Gathering, processing and other facilities
15-25
 
249

 
185

Construction in progress
(c)
 
340

 
172

Other
3-40
 
118

 
113

Total properties and equipment, at cost
 
 
9,916

 
7,986

Accumulated depreciation, depletion and amortization
 
 
(2,462
)
 
(1,829
)
Properties and equipment—net
 
 
$
7,454

 
$
6,157

__________
(a)
Estimated useful lives are presented as of December 31, 2017.
(b)
Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
(c)
Unproved properties and construction in progress are not yet subject to depreciation and depletion.
Unproved properties consist primarily of non-producing leasehold in the Delaware Basin.
Asset Retirement Obligations 
Our asset retirement obligations relate to producing wells, gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.
A rollforward of our asset retirement obligations for the years ended 2017 and 2016 is presented below.
 
 
2017
 
2016
 
(Millions)
Balance, January 1
$
45

 
$
44

Liabilities incurred
6

 
5

Liabilities settled
(11
)
 
(6
)
Estimate revisions
1

 

Accretion expense(a)
2

 
2

Balance, December 31
$
43

 
$
45

Amount reflected as current
$
7

 
$
7

__________
(a)
Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
Accretion expense associated with natural gas-producing assets in the San Juan Basin that were sold in December 2017 was approximately $4 million and $3 million for the years ended December 31, 2017 and 2016, respectively.
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable
The following table presents a summary of our accounts payable as of the dates indicated below.
 
December 31,
 
2017
 
2016
 
(Millions)
Trade
$
120

 
$
64

Accrual for capital expenditures
151

 
72

Royalties
150

 
69

Other
25

 
17

 
$
446

 
$
222


Accrued and other current liabilities
The following table presents a summary of our accrued and other current liabilities as of the dates indicated below.
 
December 31,
 
2017
 
2016
 
(Millions)
Taxes other than income taxes
$
14

 
$
15

Accrued interest
69

 
72

Compensation and benefit related accruals
39

 
51

Gathering and transportation
11

 
14

Gathering and transportation related to exited areas
53

 
57

Deferred gain and future construction obligations related to sales of gathering systems

 
66

Other, including other loss contingencies
23

 
26

 
$
209

 
$
301

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

 
$

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 debt
$
2,600

 
$
2,601

Less: Current portion of long-term debt

 

Total long-term debt
$
2,600

 
$
2,601

Less: Debt issuance costs(b)
25

 
26

Total long-term debt, net(b)
$
2,575

 
$
2,575

__________
(a)
Interest paid on debt totaled $178 million, $194 million and $120 million for 2017, 2016 and 2015, respectively.
(b)
Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
Credit Facility
On March 18, 2016, the Company entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). The Credit Facility, as amended, is now a $1.2 billion senior secured revolving credit facility with a maturity date of October 28, 2019. Based on our current credit ratings, a Collateral Trigger Period applies making the Credit Facility subject to certain financial covenants and a Borrowing Base as described below. The Credit Facility may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of December 31, 2017, WPX had no borrowings outstanding, had $70 million of letters of credit issued under the Credit Facility and was in compliance with our covenants under the credit agreement.
Borrowing Base. During a Collateral Trigger Period, loans under the Credit Facility are subject to a Borrowing Base as calculated in accordance with the provisions of the Credit Facility. In October 2017, the Borrowing Base was increased to $1.5 billion and will remain in effect until the next Redetermination Date as set forth in the Credit Facility. 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.
Terms and Conditions. The Credit Facility will initially be guaranteed by certain subsidiaries of the Company (excluding subsidiaries holding Midstream Assets and subsidiaries meeting other customary exclusion criteria), as Guarantors, and secured by substantially all of the Company’s and the Guarantors’ assets (including oil and gas properties), subject to customary exceptions and carve outs (which shall also exclude Midstream Assets and the equity interests of subsidiaries holding Midstream Assets). Such obligations shall terminate on the earlier of any applicable Collateral Trigger Termination Date (as described below) or the date on which all liens held by the Administrative Agent for the benefit of the secured parties are released pursuant to the terms of the Credit Facility.
The Collateral Trigger Termination Date is the first date following the date of the closing of the Credit Facility and the first date following any Collateral Trigger Date, as applicable, on which:
(1)
(i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s; or
(2)
both (i) the ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) is less than or equal to 3.00 to 1.00 and (ii) the Corporate Rating is (A) at least Ba1 by Moody’s and at least BB by S&P or (B) at least Ba2 by Moody’s and at least BB+ by S&P.
Interest and Commitment Fees. Interest on borrowings under the Credit Facility is payable at rates per annum equal to, at the Company’s option: (1) a fluctuating base rate equal to the alternate base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The alternate base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Company is required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility. The applicable margin and the commitment fees during a Collateral Trigger Period are determined by reference to a utilization percentage as set forth in the Credit Facility. The applicable margin and the commitment fee other than during a Collateral Trigger Period are determined by reference to a pricing schedule based on the Company’s senior unsecured non-credit enhanced debt ratings.
Significant Financial Covenants.
Currently, the Company is required to maintain:
ratio of Consolidated Secured Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than 3.25 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2017 and 3.00 to 1.00 thereafter; and
a ratio of consolidated current assets (including the unused amount of the Borrowing Base) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least 1.0 to 1.0.
If a Collateral Trigger Termination Date occurs, other financial covenants would apply.
Covenants. The Credit Facility contains customary representations and warranties and affirmative, negative and financial covenants (as described above) which were made only for the purposes of the Credit Facility and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of the Company’s subsidiaries to incur indebtedness; the ability of the Company and its subsidiaries to grant certain liens, make restricted payments, materially change the nature of its or their business, make investments, guarantees, loans or advances in non-subsidiaries or enter into certain hedging agreements; the ability of the Company’s material subsidiaries to enter into certain restrictive agreements; the ability of the Company and its material subsidiaries to enter into certain affiliate transactions; the ability of the Company and its subsidiaries to redeem any senior notes; and the Company’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person. The Company and its subsidiaries are also prohibited from using the proceeds under the Credit Facility in violation of Sanctions (as defined in the Credit Facility). In addition, the representations, warranties and covenants contained in the Credit Facility are subject to certain exceptions and/or standards of materiality applicable to the contracting parties.
Events of Default. The Credit Facility includes customary events of default, including events of default relating to:
non-payment of principal, interest or fees;
inaccuracy of representations and warranties in any material respect when made or when deemed made;
violation of covenants;
cross payment-defaults;
cross acceleration;
bankruptcy and insolvency events;
certain unsatisfied judgments;
a change of control; and
during any secured period, the failure of the collateral documents to be in effect or a lien to be valid and perfected.
If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies.
Senior Notes
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding unsecured senior note obligations at December 31, 2017.
Senior Note
 
Face Value (Millions)
 
Maturity Date
 
Interest Payment Dates
 
Optional Redemption Period(a)
7.500% Senior Notes due 2020 (the “2020 Notes”)
 
$
350

 
August 1, 2020
 
February 1, August 1
 
July 1, 2020
6.000% Senior Notes due 2022 (the “2022 Notes”)
 
$
1,100

 
January 15, 2022
 
January 15, July 15
 
October 15, 2021
8.250% Senior Notes due 2023 (the “2023 Notes”)
 
$
500

 
August 1, 2023
 
February 1, August 1
 
June 1, 2023
5.250% Senior Notes due 2024 (the “2024 Notes”)
 
$
650

 
September 15, 2024
 
March 15, September 15
 
June 15, 2024
 __________
(a)
At any time prior to these dates, we have the option to redeem some or all of the notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. On or after these dates, we have the option to redeem the notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture.
During 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.
The terms of the indentures governing our 2020 Notes, 2022 Notes, 2023 Notes and 2024 Notes are substantially identical.
Change of Control. If we experience a change of control (as defined in the indentures governing the notes) accompanied by a specified rating decline, we must offer to repurchase the notes of such series at 101% of their principal amount, plus accrued and unpaid interest.
Covenants. The terms of the indentures governing our notes restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indentures also require us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indentures. However, these limitations and requirements are subject to a number of important qualifications and exceptions. The indentures do not require the maintenance of any financial ratios or specified levels of net worth or liquidity.
Events of Default. Each of the following is an “Event of Default” under the indentures with respect to the notes of any series:
(1) a default in the payment of interest on the notes when due that continues for 30 days;
(2) a default in the payment of the principal of or any premium, if any, on the notes when due at their stated maturity,
upon redemption, or otherwise;
(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in
clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting
covenant under the indenture, which failure continues for a period of 90 days, after the date on which written notice of
such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within
such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be
automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using
commercially reasonable efforts to cure such failure; and
(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
The following table includes the provision (benefit) for income taxes from continuing operations.
 
Years Ended December 31,
 
2017
 
2016
 
2015
 
(Millions)
Provision (benefit):
 
 
 
 
 
Current:
 
 
 
 
 
Federal
$
(18
)
 
$
(26
)
 
$
(4
)
State
1

 
(7
)
 
7

 
(17
)
 
(33
)
 
3

Deferred:
 
 
 
 
 
Federal
(118
)
 
(301
)
 
12

State
(13
)
 
9

 
9

 
(131
)
 
(292
)
 
21

Total provision (benefit)
$
(148
)
 
$
(325
)
 
$
24


 
The following table provides reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes.
 
Years Ended December 31,
 
2017
 
2016
 
2015
 
(Millions)
Provision (benefit) at statutory rate
$
(56
)
 
$
(328
)
 
$
7

Increases (decreases) in taxes resulting from:
 
 
 
 
 
State income taxes (net of federal benefit)
(12
)
 
(40
)
 
3

Valuation allowance on current year state income taxes (net of federal benefit)
17

 
18

 
1

Valuation allowance on state income taxes resulting from sale (net of federal benefit)

 
8

 

Effective state income tax rate change (net of federal benefit)
(12
)
 
15

 
7

Provisional impact of Tax Cuts and Jobs Act
(92
)
 

 

Other
7

 
2

 
6

Provision (benefit) for income taxes
$
(148
)
 
$
(325
)
 
$
24


As discussed below, we record a valuation allowance on certain state net operating loss (“NOL”) carryovers generated in current years. As a result of the sale of our Piceance Basin operations in Colorado in the second quarter of 2016, we recorded $8 million of valuation allowances against Colorado NOL and credit carryovers generated in prior years.
Significant changes to our operations during 2017, 2016 and 2015 resulted in changes to our anticipated future state apportionment for our estimated state deferred tax liability. As a result of these changes and the differing state tax rates, we recorded an additional $12 million deferred tax benefit in 2017. We also accrued an additional $15 million and $7 million of deferred tax expense in 2016 and 2015, respectively.
On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“Act”). The income tax effects of changes in tax laws are recognized in the period when enacted. While the Company continues to assess the impact of the tax reform legislation on its business and consolidated financial statements, the legislation does reduce the U.S. corporate tax rate from the current rate of 35 percent to 21 percent effective January 1, 2018. This rate reduction results in a provisional estimate of a $97 million benefit offset by $5 million impact of equity based executive compensation to income tax expense in continuing operations and a corresponding reduction in the deferred tax liability. The Act provides for other significant tax law changes and modifications such as the repeal of the alternative minimum tax (“AMT”). Accordingly, AMT credits can be used to offset regular tax liability and/or can be refundable over tax years 2018-2021.
Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin (“SAB”) 118 which allows us to provide a provisional estimate of the impacts of the Act in our earnings for the year ending December 31, 2017. Our estimate does not reflect the impact of potential reductions of AMT credit refunds, changes in current interpretations of performance based executive compensation deduction limitations, effects of any state tax law changes and uncertainties regarding interpretations that may arise as a result of federal tax reform. The Company will continue to analyze the effects of the Act on its financial statements and operations. Additional impacts from the enactment of the Act will be recorded as they are identified during the one-year measurement period as provided for in SAB 118.
The following table includes significant components of deferred tax liabilities and deferred tax assets.
 
December 31,
 
2017
 
2016
 
(Millions)
Deferred tax liabilities:
 
 
 
Properties and equipment
$
792

 
$
1,295

Derivatives, net

 

Other, net
1

 
2

Total deferred tax liabilities
793

 
1,297

Deferred tax assets:
 
 
 
Accrued liabilities and other
79

 
178

Alternative minimum tax credits
78

 
104

Loss carryovers
672

 
849

Derivatives, net
42

 
66

Total deferred tax assets
871

 
1,197

Less: valuation allowance
195

 
151

Total net deferred tax assets
676

 
1,046

Net deferred tax liabilities
$
117

 
$
251


As of December 31, 2017, the Company has not completed its accounting for the tax effects of enactment of the Act; however, the Company has made a reasonable estimate of the effects on its existing deferred tax balances.
Net cash payments (refunds) for income taxes were $(39) million, $21 million and $(8) million in 2017, 2016 and 2015, respectively.
The Company has federal NOL carryovers of approximately $2,132 million at December 31, 2017, including a $353 million RKI NOL, that will not begin to expire until 2032. In addition, we have $46 million of federal capital loss carryovers at December 31, 2017, that will begin to expire in 2020.
The Company has state NOL carryovers, including the RKI carryovers, of approximately $3.8 billion and $3.1 billion at 2017 and 2016, respectively, of which more than 99 percent expire after 2029.
We have recorded valuation allowances against deferred tax assets attributable primarily to certain state NOL carryovers as well as our federal capital loss carryover. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent we 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. As of December 31, 2017, our assessment of federal net operating loss carryovers was that no valuation allowance was required; however, a future pretax loss may result in the need for a valuation allowance on our deferred tax assets.
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 December 31, 2017, we do not believe that an Ownership Change has occurred for WPX, but an Ownership Change did occur for RKI effective with the RKI Acquisition. Therefore, there is an annual limitation on the benefit that WPX can claim from RKI carryovers that arose prior to the RKI 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. 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 adjustments 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.
The Company files a consolidated federal income tax return and several state income tax returns. The Company’s federal income tax returns for tax years 2014 through 2016 remain open for examination. The statute of limitations for most states expires one year after expiration of the IRS statute. During the year ended December 31, 2017, the IRS began an examination of the Company’s 2014 and 2015 federal income tax returns. In addition, the IRS began an examination of RKI’s 2014 and short-period 2015 federal income tax returns. These examinations remain in the preliminary stage and no additional taxes or refunds have been recorded at this time.
The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are less than $1 million for 2017. The impact of this accrual is included within Other in our reconciliation of the provision (benefit) at statutory rate to recorded provision (benefit) for income taxes.
As of December 31, 2017, the Company has approximately $8 million of unrecognized tax benefits which is offset by an increase in deferred tax assets of approximately $7 million. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of an unrecognized tax benefit.
Contingent Liabilities and Commitments
Contingent Liabilities and Commitments
Contingent Liabilities and Commitments
Contingent Liabilities
Royalty litigation
In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, breach of implied duty to market, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico where the court denied plaintiffs’ motion for class certification. In March 2017, plaintiffs appealed the denial of class certification to the Tenth Circuit and oral argument before the Tenth Circuit was held on January 17, 2018. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico and violation of the New Mexico Oil and Gas Proceeds Payment Act, and seek declaratory judgment, accounting and injunctive relief. On August 16, 2016, the court denied plaintiffs’ motion for class certification. On September 15, 2016, plaintiffs filed their motion for reconsideration and filed a second motion for class certification, and on September 30, 2017, the Court issued its memorandum opinion and order denying the plaintiffs motion for reconsideration and their Second Motion for Class Certification. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to many of our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. Similar guidelines were recently issued for certain leases in Colorado and, as in the case of the New Mexico guidelines, we do not believe that they will result in a material difference to our historical federal royalty payments. ONRR has asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas.
Environmental matters
The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Matters related to Williams’ former power business
In connection with a Separation and Distribution Agreement between WPX and 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. Additionally, Federal and state laws in areas of former operations may require previous operators to perform in certain circumstances where the buyer/operator may no longer be able to perform.
The indemnity provided to the purchaser of the entity that held our Piceance Basin operations relates in substantial part to liabilities arising in connection with litigation over the appropriate calculation of royalty payments. Plaintiffs in that litigation have asserted claims regarding, among other things, the method by which we took transportation costs into account when calculating royalty payments. In 2017, we settled one of these claims.
As of December 31, 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 December 31, 2017 and December 31, 2016, the Company had accrued approximately $11 million and $13 million, respectively, for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
Commitments
We have minimum commitments with midstream companies for gathering, treating, processing and transportation services associated with moving certain of our production to market. As part of managing our commodity price risk, we may also utilize contracted pipeline capacity to move our natural gas production and third-party purchases of natural gas to other locations in an attempt to obtain more favorable pricing differentials. During 2015 and 2016 we divested most of our contracted pipeline capacity in conjunction with our exits from the Piceance and Appalachian Basins. During 2017, we entered into various contracts for pipeline capacity to move our Permian Basin production to market. The midstream service and transportation contract commitments disclosed below include obligations for which liabilities were recorded in 2015 associated with our exit from the Powder River Basin and our abandonment of an area in the Appalachian Basin. Amounts below also include obligations totaling $317 million associated with our San Juan Basin operations that will be assumed by the purchaser (see Note 17). As of December 31, 2017, commitments and recorded liabilities associated with our midstream service and transportation contracts are as follows:
 
 
Midstream Services
 
Transportation
 
Total
 
(Millions)
2018
$
106

 
$
55

 
$
161

2019
101

 
57

 
158

2020
103

 
60

 
163

2021
91

 
44

 
135

2022
81

 
33

 
114

Thereafter
219

 
279

 
498

Total commitments
$
701

 
$
528

 
$
1,229

 
 
 
 
 
 
Accrued liabilities
$
34

 
$
67

 
$
101


Our midstream service commitments will be settled over approximately eight years.
Future minimum annual rentals under noncancelable operating leases as of December 31, 2017, are payable as follows:
 
(Millions)
2018
$
7

2019
5

2020
5

2021
4

2022
1

Thereafter

 
 
Total
$
22


Total rent expense, excluding amounts capitalized, was $25 million, $30 million and $28 million in 2017, 2016 and 2015, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting; however, charges for rig release penalties or long term standby charges are expensed as incurred.
Employee Benefit Plans
Employee Benefit Plans
Employee Benefit Plans
WPX has a defined contribution plan which matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $11 million, $13 million and $15 million for 2017, 2016 and 2015, respectively. Approximately $7 million, $7 million and $9 million were included in accrued and other current liabilities at December 31, 2017, 2016 and 2015, respectively, related to the non-matching annual employer contribution.
Stock-Based Compensation
Stock-Based Compensation
Stock-Based Compensation
We have an equity incentive plan (“2013 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2013 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards (restricted stock awards, restricted stock units, performance shares and performance units are collectively referred to as restricted stock units and awards for purposes of this footnote). At December 31, 2017, 14 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 6 million shares were available for future grants. The 2013 Incentive Plan is administered by either the full Board of Directors or a committee as designated by the Board of Directors, determined by the grant. Our employees, officers and non-employee directors are eligible to receive awards under the 2013 Incentive Plan.
Total stock-based compensation expense was $30 million, $33 million and $31 million for of the years ended December 31, 2017, 2016 and 2015, respectively, and is reflected in general and administrative expense. Measured but unrecognized stock-based compensation expense related to restricted stock units and awards at December 31, 2017 was $36 million and is expected to be recognized over a weighted-average period of 1.8 years. There was no unrecognized stock-based compensation expense related to stock options at December 31, 2017.
The ESPP allows employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. Offering periods are from January through June and from July through December. Employees purchased 122 thousand shares at an average price of $8.34 per share during 2017.
Nonvested Restricted Stock Units and Awards
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2017.
Restricted Stock Units
Shares
 
Weighted-
Average
Fair Value(a)
 
(Millions)
 
 
Nonvested at December 31, 2016
6.5

 
$
11.92

Granted
2.4

 
$
13.76

Forfeited
(0.7
)
 
$
12.72

Vested
(2.5
)
 
$
13.18

Nonvested at December 31, 2017
5.7

 
$
12.06

__________
(a)
Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price.
Other restricted stock unit information
 
2017
 
2016
 
2015
Weighted-average grant date fair value of restricted stock units granted during the year, per share
$
13.76

 
$
10.99

 
$
10.24

Total fair value of restricted stock units vested during the year (millions)
$
33

 
$
37

 
$
40


Performance-based shares granted represent 31 percent of nonvested restricted stock units outstanding at December 31, 2017. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2017.
Stock Options
Options
 
Weighted-
Average
Exercise
Price
 
Weighted-Average Remaining Contractual Life
 
Aggregate
Intrinsic
Value
 
(Millions)
 
 
 
(Years)
 
(Millions)
Outstanding at December 31, 2016
2.7

 
$
15.31

 
 
 
$
4

Granted

 
$

 
 
 
 
Exercised
(0.1
)
 
$
8.06

 
 
 
 
Forfeited
(0.4
)
 
$
15.96

 
 
 
 
Outstanding at December 31, 2017
2.2

 
$
15.35

 
2.2
 
$
3

Exercisable at December 31, 2017
2.2

 
$
15.35

 
2.2
 
$
3



The total intrinsic value of options exercised was $224 thousand, $160 thousand and $319 thousand for the years ended December 31, 2017, 2016 and 2015, respectively.
Cash received from stock option exercises was $0.4 million, $0.4 million and $2 million during 2017, 2016 and 2015, respectively.
The Company did not grant stock options during the years ended 2017, 2016 and 2015.
Stockholders' Equity
Stockholders' Equity
Stockholders’ Equity
Preferred Stock
Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding. As of December 31, 2017, there were 4.8 million shares of our 6.25% series A Mandatory Convertible Preferred Stock (“Preferred Stock”) issued and outstanding (as described below).
Series A Mandatory Convertible Preferred Stock
On July 22, 2015, we issued 7 million shares, $0.01 par value, pursuant to a registered public offering, of our Preferred Stock at $50 per share, for gross proceeds of approximately $350 million, before underwriting discounts and commissions.
Dividends on our Preferred Stock will be payable on a cumulative basis when, as and if declared by our Board of Directors, or an authorized committee of our Board of Directors, at an annual rate of 6.25% of the liquidation preference of $50 per share. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock, or in any combination of cash and shares of our common stock on January 31, April 30, July 31 and October 31 of each year, commencing on October 31, 2015 and ending on, and including, July 31, 2018.
Each share of our Preferred Stock has a liquidation preference of $50 and, unless converted or redeemed earlier, each share of our Preferred Stock will automatically convert on July 31, 2018 into between 4.1254 and 4.9504 shares of our common stock (respectively, the “minimum conversion rate” and “maximum conversion rate”), subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion will be determined based on the average volume weighted average price per share of our common stock over the 20 consecutive trading day period beginning on, and including, the 23rd scheduled trading day immediately preceding July 31, 2018, which we refer to as the “final averaging period.” At any time prior to July 31, 2018, a holder may convert one share of our Preferred Stock into a number of shares of our common stock equal to the minimum conversion rate of 4.1254, subject to anti-dilution adjustments.
On July 20, 2016, we entered into Conversion Agreements with certain existing beneficial owners (the “Preferred Holders”) of our Preferred Stock, pursuant to which each of the Preferred Holders agreed to convert (the “Conversion”) shares of Preferred Stock it beneficially owned into shares of our common stock, par value $0.01 per share, and in addition receive a cash payment from us in connection with the Conversion. The Preferred Holders agreed to convert an aggregate of approximately 2.2 million shares of Preferred Stock into approximately 10.2 million shares of our common stock in the Conversion, and we made an aggregate cash payment to the Preferred Holders of approximately $10 million. Following the Conversion, approximately 4.8 million shares of Preferred Stock remain outstanding. We issued the shares of common stock in the Conversion on July 28, 2016. As a result of the cash payment and additional shares issued as an inducement to the Preferred Holders, we recorded a loss of $22 million in 2016.
By entering into the Conversion and associated transactions early, we reduced cash dividend payments and continued simplifying our capital and cost structure.
Common Stock
Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends on our common stock were declared or paid for 2017, 2016 or 2015. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
Subject to certain exceptions, so long as any share of our Preferred Stock remains outstanding, no dividend or distribution shall be declared or paid on the shares of the Company’s common stock or any other class or series of junior stock, and no common stock or any other class or series of junior or parity stock shall be purchased, redeemed or otherwise acquired for consideration by the Company or any of its subsidiaries unless all accumulated and unpaid dividends for all preceding dividend periods have been declared and paid upon, or a sufficient sum of cash or number of shares of the Company’s common stock has been set apart for the payment of such dividends upon, all outstanding shares of Preferred Stock.
On July 22, 2015, we completed an equity offering of 30 million shares of our common stock for gross proceeds of approximately $292 million, net of underwriter discounts and commissions, at the public offering price of $10.10 per share.
On August 17, 2015, we issued 40 million unregistered shares of our common stock to RKI shareholders as part of the consideration under our merger agreement. The estimated fair value of the shares on the RKI Acquisition date was $296 million. These shares were registered in December 2015. See Note 2 for further discussion of the RKI Acquisition.
On June 6, 2016, we completed an underwritten public offering of 56.925 million shares of our common stock, which included 7.425 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 $9.47 per share and we received proceeds of approximately $538 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
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. We used these proceeds, and cash on hand, to close the Panther Acquisition.
Fair Value Measurements
Fair Value Measurements
Fair Value Measurements
Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.
Level 2—Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps and options. These options, which hedge future sales of production, are structured as costless collars, calls or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. 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.
Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash and margin deposits approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
December 31, 2017
 
December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$

 
$
59

 
$

 
$
59

 
$

 
$
38

 
$

 
$
38

Energy derivative liabilities
$

 
$
236

 
$

 
$
236

 
$

 
$
215

 
$

 
$
215

Total debt(a)
$

 
$
2,746

 
$

 
$
2,746

 
$

 
$
2,702

 
$

 
$
2,702

__________
(a)
The carrying value of total debt, excluding capital leases and debt issuance costs, was $2,600 million as of December 31, 2017 and 2016.
Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Forward, swap, option and swaption contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars, 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 and calls to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions and calls grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio extends through the end of 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 monthly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. There were no instruments included in Level 3 at December 31, 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 between Level 1 and Level 2 occurred during the years ended December 31, 2017 or 2016.
Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues on our Consolidated Statements of Operations.
Other
In addition to the items discussed below, we performed other nonrecurring fair value assessments as discussed in Note 2.
2017
In conjunction with the $103 million of gains from exchanges of leasehold during 2017, 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. The total fair value of leasehold exchanges in 2017 approximated $200 million. See Note 5 for additional discussion related to leasehold exchanges.
In addition, during 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. 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 which resulted in an impairment of $60 million recorded in the third-quarter of 2017. See Note 5 for additional discussion related to the impairment of our natural gas-producing properties in the San Juan Basin.
2015
As previously noted, we evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. On several occasions in the past three years, we considered the significant declines in forward natural gas, oil and NGL prices as compared to the previous respective period’s forward prices to be indicators of a potential impairment. As a result, we assessed the carrying value of our producing properties and costs of acquired unproved reserves for impairments as of the dates of those declines. Our assessments utilized estimates of future cash flows, including in some instances potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of proved, probable and possible reserve quantities, estimates of future commodity prices (developed in consideration of market information, internal forecasts and published forward prices adjusted for locational basis differentials), expectation for market participant drilling plans, expected capital costs and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. In the year ended December 31, 2015, our assessment identified certain properties with a carrying value in excess of their calculated fair values and as a result, we recorded impairment charges. The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
 
Total losses for the year ended December 31,
 
 
 
2015 (a)
 
 
 
 
Impairments:
 
 
 
 
Producing properties and costs of acquired unproved reserves (Note 3 and Note 5)
 
 
$
2,308

 
Unproved leasehold
 
 
26

 
 
 
 
$
2,334

 
__________
(a)
As a result of our impairment assessment in 2015, we recorded the following significant impairment charges that are reported in discontinued operations, for which the fair value measured for these properties at December 31, 2015 was estimated to be approximately $880 million:
$2,308 million impairment charge related to natural gas-producing properties in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these properties included estimated cash flows from a potential divestment.
$26 million impairment charge on our unproved leasehold acreage in the Piceance Basin, reported in discontinued operations, as a result of the impairment of the producing properties in conjunction with a potential divestment.
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 December 31, 2017.
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
Crude Oil
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
2018
 
Fixed Price Swaps
 
WTI
 
(57,500)
 
$
52.82

Crude Oil
 
2018
 
Basis Swaps
 
Midland
 
(17,521)
 
$
(0.91
)
Crude Oil
 
2018
 
Basis Swaps
 
Nymex
 
(20,000)
 
$
0.03

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

Crude Oil
 
2019
 
Fixed Price Swaps
 
WTI
 
(32,000)
 
$
51.99

Crude Oil
 
2019
 
Basis Swaps
 
Midland
 
(20,000)
 
$
(0.93
)
Crude Oil
 
2019
 
Basis Swaps
 
Nymex
 
(20,000)
 
$
0.11

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

Crude Oil
 
2020
 
Basis Swaps
 
Midland
 
(5,000)
 
$
(1.16
)
 
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
2018
 
Fixed Price Swaps
 
Henry Hub
 
(140)
 
$
2.97

Natural Gas
 
2018
 
Basis Swaps
 
San Juan
 
(40)
 
$
(0.30
)
Natural Gas
 
2018
 
Basis Swaps
 
Permian
 
(48)
 
$
(0.31
)
Natural Gas
 
2018
 
Basis Swaps
 
Waha
 
(15)
 
$
0.93

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

Natural Gas
 
2019
 
Fixed Price Swaps
 
Henry Hub
 
(50)