WPX ENERGY, INC., 10-K filed on 2/27/2014
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2013
Feb. 26, 2014
Jun. 30, 2013
Document Documentand Entity Information [Abstract]
 
 
 
Document Type
10-K 
 
 
Amendment Flag
false 
 
 
Document Period End Date
Dec. 31, 2013 
 
 
Document Fiscal Year Focus
2013 
 
 
Document Fiscal Period Focus
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
 
201,737,171 
 
Entity Public Float
 
 
$ 3,775,544,298 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Current assets:
 
 
Cash and cash equivalents
$ 99 
$ 153 
Accounts receivable, net of allowance of $7 and $11 as of December 31, 2013 and 2012, respectively
536 
443 
Deferred income taxes
49 
17 
Derivative assets
50 
58 
Inventories
72 
66 
Margin deposits
71 
Other
45 
35 
Total current assets
922 
772 
Investments
145 
145 
Properties and equipment, net (successful efforts method of accounting)
7,241 
8,416 
Derivative assets
Other noncurrent assets
114 
121 
Total assets
8,429 
9,456 
Current liabilities:
 
 
Accounts payable
652 
509 
Accrued and other current liabilities
190 
201 
Customer margin deposits payable
55 
Derivative liabilities
110 
14 
Total current liabilities
1,007 
726 
Deferred income taxes
788 
1,401 
Long-term debt
1,916 
1,508 1
Derivative liabilities
12 
Asset retirement obligations
358 
316 
Other noncurrent liabilities
138 
133 
Contingent liabilities and commitments (Note 11)
   
   
Stockholders’ equity:
 
 
Preferred stock (100 million shares authorized at $0.01 par value; no shares issued)
Common stock (2 billion shares authorized at $0.01 par value; 201 million shares issued at December 31, 2013 and 199.3 million shares issued at December 31, 2012)
Additional paid-in-capital
5,516 
5,487 
Accumulated deficit
(1,408)
(223)
Accumulated other comprehensive income (loss)
(1)
Total stockholders’ equity
4,109 
5,268 
Noncontrolling interests in consolidated subsidiaries
101 
103 
Total equity
4,210 
5,371 
Total liabilities and equity
$ 8,429 
$ 9,456 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 7 
$ 11 
Preferred stock, par value
$ 0.01 
$ 0.01 
Preferred stock, shares authorized
100,000,000 
100,000,000 
Preferred stock, shares issued
Common stock, par value
$ 0.01 
$ 0.01 
Common stock, shares authorized
2,000,000,000 
2,000,000,000 
Common stock, shares issued
201,000,000 
199,300,000 
Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Product revenues:
 
 
 
Natural gas sales
$ 1,093 
$ 1,364 
$ 1,694 
Oil and condensate sales
649 
491 
312 
Natural gas liquid sales
230 
299 
408 
Total product revenues
1,972 
2,154 
2,414 
Gas management
891 
949 
1,428 
Net gain (loss) on derivatives not designated as hedges (Note 16)
(124)
78 
29 
Other
22 
11 
Total revenues
2,761 
3,189 
3,882 
Costs and expenses:
 
 
 
Lease and facility operating
308 
283 
262 
Gathering, processing and transportation
433 
506 
487 
Taxes other than income
141 
111 
134 
Gas management, including charges for unutilized pipeline capacity
931 
996 
1,471 
Exploration (Note 6)
431 
83 
126 
Depreciation, depletion and amortization
940 
966 
902 
Impairment of producing properties and costs of acquired unproved reserves (Note 6)
1,055 1 2
225 1 3
367 1 4
Gain on sale of Powder River Basin deep rights leasehold
(36)
General and administrative
289 
287 
275 
Other—net
17 
12 
Total costs and expenses
4,509 
3,469 
4,024 
Operating income (loss)
(1,748)
(280)
(142)
Interest expense
(108)
(102)
(117)
Interest capitalized
Investment income, impairment of equity method investment and other
30 
26 
Income (loss) from continuing operations before income taxes
(1,846)
(344)
(224)
Provision (benefit) for income taxes
(655)
(111)
(74)
Income (loss) from continuing operations
(1,191)
(233)
(150)
Income (loss) from discontinued operations
22 
(142)
Net income (loss)
(1,191)
(211)
(292)
Less: Net income (loss) attributable to noncontrolling interests
(6)
12 
10 
Net income (loss) attributable to WPX Energy, Inc.
$ (1,185)
$ (223)
$ (302)
Basic and diluted earnings (loss) per common share (Note 5):
 
 
 
Income (loss) from continuing operations (in dollars per share)
$ (5.91)
$ (1.23)
$ (0.81)
Income (loss) from discontinued operations (in dollars per share)
$ 0.00 
$ 0.11 
$ (0.72)
Net income (loss) (in dollars per share)
$ (5.91)
$ (1.12)
$ (1.53)
Weighted-average shares
200.5 
198.8 
197.1 
[2] As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million •$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.•$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.•$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
[3] As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.•$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.•$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
[4] As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.•$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent. •$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
Consolidated Statements of Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Statement of Partners' Capital [Abstract]
 
 
 
Net income (loss) attributable to WPX Energy, Inc.
$ (1,185)
$ (223)
$ (302)
Other comprehensive income (loss):
 
 
 
Change in fair value of cash flow hedges, net of tax
1
57 1
262 1
Net reclassifications into earnings of net cash flow hedge gains, net of tax
(3)2
(274)2
(211)2
Other comprehensive income (loss), net of tax
(3)
(217)
51 
Comprehensive income (loss) attributable to WPX Energy, Inc.
$ (1,188)
$ (440)
$ (251)
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Statement of Partners' Capital [Abstract]
 
 
 
Income tax for net cash flow hedges
 
$ 33 
$ 151 
Unrealized gains recognized for hedge transactions
 
15 
 
Income tax provision for cash flow hedge gains
159 
120 
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)
$ 5 
$ 434 
$ 331 
Consolidated Statements of Changes in Equity (USD $)
In Millions, unless otherwise specified
Total
Total Stockholders’ Equity
Common Stock
Capital in Excess of Par Value
Accumulated Deficit
Williams’ Net Investment
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
Balance at beginning of period at Dec. 31, 2010
$ 4,484 
$ 4,412 
$ 0 
$ 0 
 
$ 4,244 
$ 168 
$ 72 1
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss)
(292)
(302)
 
 
 
(302)
 
10 1
Other comprehensive income (loss)
51 
51 
 
 
 
 
51 
 
Comprehensive income (loss)
(241)
 
 
 
 
 
 
 
Contribution of Notes Payable to Williams (Note 3)
2,420 
2,420 
 
 
 
2,420 
 
 
Allocation of alternative minimum tax credit (Note 10)
98 
98 
 
 
 
98 
 
 
Net transfers with Williams
(25)
(25)
 
 
 
(25)
 
 
Distribution to Williams a portion of note proceeds
(981)
(981)
 
 
 
(981)
 
 
Recapitalization upon contribution by Williams
 
5,452 
 
(5,454)
 
 
Dividends to noncontrolling interests
(1)
 
 
 
 
 
 
(1)1
Stock based compensation, net of tax benefit
 
 
 
 
 
Balance at end of period at Dec. 31, 2011
5,759 
5,678 
5,457 
219 
81 1
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss)
(211)
(223)
 
 
(223)
 
 
12 1
Other comprehensive income (loss)
(217)
(217)
 
 
 
 
(217)
 
Comprehensive income (loss)
(428)
 
 
 
 
 
 
 
Contribution from noncontrolling interest
10 
 
 
 
 
 
 
10 1
Stock based compensation, net of tax benefit
30 
30 
 
30 
 
 
 
 
Balance at end of period at Dec. 31, 2012
5,371 
5,268 
5,487 
(223)
 
103 1
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss)
(1,191)
(1,185)
 
 
(1,185)
 
 
(6)1
Other comprehensive income (loss)
(3)
(3)
 
 
 
 
(3)
 
Comprehensive income (loss)
(1,194)
 
 
 
 
 
 
 
Contribution from noncontrolling interest
 
 
 
 
 
 
1
Stock based compensation, net of tax benefit
29 
29 
 
29 
 
 
 
 
Balance at end of period at Dec. 31, 2013
$ 4,210 
$ 4,109 
$ 2 
$ 5,516 
$ (1,408)
 
$ (1)
$ 101 1
Consolidated Statements of Changes in Equity (Parenthetical)
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Noncontrolling interest, ownership percentage by noncontrolling owners
31.00% 
31.00% 
31.00% 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Operating Activities
 
 
 
Net income (loss)
$ (1,191)
$ (211)
$ (292)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
940 
973 
951 
Deferred income tax provision (benefit)
(645)
(160)
(176)
Provision for impairment of properties and equipment (including certain exploration expenses) and investments
1,483 
288 
694 
Amortization of stock-based awards
32 
28 
Gain on sales of assets
41 1
42 1
Cash provided (used) by operating assets and liabilities:
 
 
 
Accounts receivable
(43)
68 
(100)
Inventories
(5)
Margin deposits and customer margin deposit payable
(18)
(5)
(18)
Other current assets
(7)
(11)
Accounts payable
41 
(128)
131 
Accrued and other current liabilities
(21)
12 
10 
Changes in current and noncurrent derivative assets and liabilities
106 
(32)
Other, including changes in other noncurrent assets and liabilities
(9)
Net cash provided by operating activities
636 
796 
1,207 
Investing Activities
 
 
 
Capital expenditures
(1,154)2
(1,521)2
(1,572)2
Proceeds from sales of assets
49 
310 
15 
Purchases of investments
(3)
(2)
(12)
Other
(3)
13 
Net cash used in investing activities
(1,111)
(1,204)
(1,556)
Financing Activities
 
 
 
Proceeds from common stock
Proceeds from long-term debt
1,502 
Borrowings on credit facility
970 
50 
Payments on credit facility
(560)
(50)
Contribution from noncontrolling interest
10 
Excess tax benefit of stock based awards
13 
Payments for debt issuance costs
(30)
Net increase in notes payable to Williams
159 
Net changes in Williams’ net investment
(777)
Other
(15)
Net cash provided by financing activities
426 
37 
839 
Net increase (decrease) in cash and cash equivalents
(49)
(371)
490 
Effect of Exchange Rate on Cash and Cash Equivalents
(5)
(2)
(1)
Cash and cash equivalents at beginning of period
153 
526 
37 
Cash and cash equivalents at end of period
$ 99 
$ 153 
$ 526 
Consolidated Statements of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Statement of Cash Flows [Abstract]
 
 
 
Gain on sale of Powder River Basin deep rights leasehold
$ 36 
$ 0 
$ 0 
Increase to properties and equipment
(1,207)
(1,449)
(1,641)
Changes in related accounts payable and accounts receivable
53 
(72)
69 
Capital expenditures
$ (1,154)1
$ (1,521)1
$ (1,572)1
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
Description of Business
Operations of our company are located in the United States and South America and are organized into domestic and international reportable segments. WPX Energy, Inc. was formed in 2011 by The Williams Companies, Inc. (“Williams”) to effect the separation of its exploration and production business. Williams contributed to the Company its investment in certain subsidiaries related to Williams’ domestic and international exploration and production businesses, collectively referred to as the “Contribution”. The separation was completed on December 31, 2011 through a pro rata distribution of WPX common stock to Williams’ stockholders.
Domestic includes natural gas, oil and NGL development, production and gas management activities located in Colorado, New Mexico, North Dakota, Pennsylvania and Wyoming in the United States. We specialize in development and production from tight-sands and shale formations and coal bed methane reserves in the Piceance, Williston, San Juan, Powder River, Appalachian and Green River Basins. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.
International primarily consists of our ownership in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia.
The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we”, “us” or “our”.
Basis of Presentation
These financial statements are prepared on a consolidated basis. Prior to the Contribution, the financial statements were derived from the financial statements and accounting records of Williams using the historical results of operations and historical basis of the assets and liabilities of the Contribution to WPX. Management believes the assumptions underlying the financial statements are reasonable. The financial statements of 2011 included herein may not necessarily reflect the Company’s results of operations, financial position and cash flows in the future or what its results of operations, financial position and cash flows would have been had the Company been a stand-alone company during 2011. Because a direct ownership relationship did not exist prior to the Contribution among the various entities that comprise the Company, Williams’ net investment in the Company, excluding notes payable to Williams, has been shown as Williams’ net investment within stockholder’s equity in the consolidated financial statements. In connection with the Contribution, we have reflected the amounts previously presented as Williams’ net investment in excess of the par value of our common stock as additional paid-in capital. Transactions in 2011 with Williams’ other operating businesses, which generally settled monthly, are shown as changes in accounts receivable or accounts payable in the Consolidated Statements of Cash Flows for the year ended December 31, 2011. Other transactions during the period prior to separation between the Company and Williams which were not part of the notes payable to Williams have been identified in the Consolidated Statements of Equity as net transfers with Williams (see Note 3).
Discontinued operations
During the second quarter of 2012, we completed the sale of our holdings in the Barnett Shale and the Arkoma Basin. We have reported the results of operations and financial position of the Barnett Shale and Arkoma Basin operations as discontinued operations for all periods presented.
Additionally, see Note 11 for a discussion of contingencies related to Williams’ former power business (most of which was disposed in 2007).
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions which impact these financials include:
Impairment assessments of long-lived assets;
Valuations of derivatives;
Estimation of natural gas and oil 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 of our domestic operations consists of approximately $21 million and $19 million at December 31, 2013 and 2012, respectively, primarily related to escrow accounts established as part of the settlement agreement with certain California utilities and is included in other current and noncurrent assets. Included in the separation and distribution agreement with Williams are indemnifications requiring us to pay to Williams any net asset (or receive any net liability) that result upon ultimate resolution of these matters (see Note 11). Additionally, restricted cash of our international segment consists of approximately $6 million and $9 million at December 31, 2013 and 2012, respectively, associated with various letters of credit that is also classified in other current and other noncurrent assets.
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 inventories consist of tubular goods and production equipment for future transfer to wells of $49 million and $42 million at December 3l, 2013 and 2012, respectively. Additionally, we have natural gas in storage related to our gas management activities of $13 million and $24 million at December 31, 2013 and 2012, respectively, and crude oil production in transit of $10 million at December 31, 2013. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. We recognized lower of cost or market writedowns on natural gas in storage of $1 million, $11 million and $10 million in 2013, 2012 and 2011, respectively.
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 expense. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statements of Operations. A majority of the costs of acquired unproved reserves are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.
Other capitalized costs
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 for our domestic properties or on a concession basis for our international properties. International concession reserve estimates are limited to production quantities estimated through the life of the concession. 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.
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.
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.
Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.
Contingent liabilities
Owing 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 our credit facilities 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.
For many of our commodity derivatives entered into prior to January 1, 2012, we designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship it must meet specific criteria and we must maintain appropriate documentation. We established hedging relationships pursuant to our risk management policies. We evaluated the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
Certain gains and losses on derivative instruments included in the Consolidated Statements of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;
The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
Realized gains and losses on all derivatives that settle financially;
Realized gains and losses on derivatives held for trading purposes; and
Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Product revenues
Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2013 and 2012 was insignificant. Additionally, natural gas revenues include $5 million, $423 million and $326 million in 2013, 2012 and 2011, respectively, of realized gains from derivatives designated as cash flow hedges of our production sold.
Gas management revenues and expenses
Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Our gas management activities through May 2012 included purchases and subsequent sales to Williams Partners for fuel and shrink gas (see Note 3). Additionally, gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas, oil and NGLs purchased from working interest owners in operated wells and other area third party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
Charges for unutilized transportation capacity included in gas management expenses were $61 million, $46 million and $35 million in 2013, 2012 and 2011, respectively.
Capitalization of interest
We capitalize interest during construction on projects with construction periods of at least three months or a total estimated project cost in excess of $1 million. The interest rate used until June 30, 2011 was the rate charged to us by Williams through June 30, 2011, at which time our intercompany note with Williams was forgiven (see Note 3). We did not capitalize interest for the period from July 1, 2011 to mid November 2011. Beginning November 2011, we began using the weighted average rate of our long-term notes payable which were issued in November 2011 (see Note 9).
Income taxes
We file consolidated and combined federal and state income tax returns for the Company and its subsidiaries. Through the effective date of the spin-off, the Company’s domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provisions for 2011 were calculated on a separate return basis for us and our subsidiaries, except for certain adjustments. 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.
Employee stock-based compensation
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Through the date of the spin-off, certain employees providing direct service to us participated in Williams’ common-stock-based awards plans. The plans provided for Williams’ common-stock-based awards to both employees and Williams’ non-management directors. The plans permitted the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards were granted for no consideration other than prior and future services or based on certain financial performance targets.
Through the date of the spin-off, Williams charged us for compensation expense related to stock-based compensation awards granted to our direct employees. Stock based compensation was also a component of allocated amounts charged to us by Williams for general and administrative personnel providing services on our behalf.
In preparation for the spin-off, Williams’ Compensation Committee determined that all outstanding Williams’ equity-based compensation awards, whether vested or unvested, other than outstanding options issued prior to January 1, 2006 (“Pre-2006 Options”) would convert into awards with respect to shares of common stock of the company that continues to employ the holder following the spin-off. The Pre-2006 Options were converted into options covering both Williams and WPX common stock. The number of shares underlying each award and, with respect to options, the per share exercise price of each such award has been adjusted to maintain, on a post-spin-off basis, the pre-spin-off intrinsic value of such awards.
Foreign exchange
Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
Earnings (loss) per common share
Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units (see Note 5).
Discontinued Operations
Discontinued Operations
Discontinued Operations
During the first quarter of 2012, our management signed an agreement to divest its holdings in the Barnett Shale and the Arkoma Basin. The transaction closed in second-quarter 2012. Total proceeds received from the sale were $306 million.
Summarized Results of Discontinued Operations
 
 
2012
 
2011
 
(Millions)
Revenues
 
$
28

 
$
118

Income (loss) from discontinued operations before gain on sale, impairments and income taxes
 
$
(3
)
 
$
(15
)
Gain on sale
 
38

 

Impairments
 

 
(209
)
Less: Provision (benefit) for income taxes
 
13

 
(82
)
Income (loss) from discontinued operations
 
$
22

 
$
(142
)

The impairments in 2011 reflect write-downs to estimates of fair value of our holdings in the Barnett Shale and the Arkoma Basin. Impairment charges on our Fort Worth (Barnett Shale) properties were $180 million in 2011. Impairment charges in Arkoma were $29 million in 2011. These nonrecurring fair value measurements, which fall within Level 3 of the fair value hierarchy, utilized a probability-weighted discounted cash flow analysis that was based on internal cash flow models.
Transactions with Williams
Transactions with Williams
Transactions with Williams
During the fourth quarter of 2011, the Contribution and recapitalization of the Company was completed, whereby common stock held by Williams converted into approximately 197 million shares of WPX common stock. We also entered into agreements with Williams in connection with our separation. These agreements include:
A Separation and Distribution agreement for, among other things, the separation from Williams and the distribution of WPX common stock, the distribution of a portion of the net proceeds from the debt financing as well as agreements between us and Williams, including those relating to indemnification;
A tax sharing agreement, providing for, among other things, the allocation between Williams and WPX of federal, state, local and foreign tax liabilities for periods prior to the distribution and in some instances for periods after the distribution;
An employee matters agreement discussed below; and
A transition services agreement for one year following separation.
Personnel and related services
As previously discussed, our domestic operations were contributed to WPX Energy, Inc. on July 1, 2011. On June 30, 2011, certain entities that were contributed to us on July 1, 2011 withdrew from the Williams’ benefit plans and terminated their personnel services agreements with Williams’ payroll companies.
 
Simultaneously, two new administrative service entities owned and controlled by Williams executed new personnel services agreements with the payroll companies and joined the Williams plans as participants. The effect of these transactions is that none of the companies contributed to WPX Energy in June 2011 had any employees. Through December 30, 2011, these service entities employed all personnel that provided services to the Company and remained owned and controlled by Williams.
In connection with the spin-off, we entered into an Employee Matters Agreement with Williams that set forth our agreements with Williams as to certain employment, compensation and benefits matters. The Employee Matters Agreement provides for the allocation and treatment of assets and liabilities arising out of employee compensation and benefit programs in which our employees participated prior to January 1, 2012. In connection with the spin-off, we provided benefit plans and arrangements in which our employees will participate going forward. Generally, other than with respect to equity compensation (discussed below), from and after January 1, 2012, we sponsored and maintained employee compensation and benefit programs relating to all employees who transferred to us from Williams in connection with the spin-off through the contribution of two newly established service entities that employees of Williams were moved to prior to the spin-off. The Employee Matters Agreement provides that Williams will remain solely responsible for all liabilities under The Williams Companies Pension Plan, The Williams Companies Retirement Restoration Plan and The Williams Companies Investment Plus Plan. No assets and/or liabilities under any of those plans transferred to us or our benefit plans and our employees ceased active participation in those plans as of January 1, 2012.
All outstanding Williams equity awards (other than stock options granted prior to January 1, 2006) held by our employees as of the spin-off were converted into WPX equity awards, issued pursuant to a plan that we established (see Note 13). In addition, outstanding Williams stock options that were granted prior to January 1, 2006 and held by our employees and Williams’ other employees as of the date of the spin-off were converted into options to acquire both WPX common stock and Williams common stock, in the same proportion as the number of shares of WPX common stock that each holder of Williams common stock received in the spin-off. The conversion maintained the same intrinsic value as the applicable Williams equity award as of the date of the conversion.
Through the date of the spin-off, Williams charged us for the payroll and benefit costs associated with operations employees (referred to as direct employees) and carried the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement and medical plans. Our share of those costs was charged to us through affiliate billings and reflected in lease and facility operating and general and administrative within costs and expenses in the accompanying Consolidated Statements of Operations.
In addition, Williams charged us for certain employees of Williams who provided general and administrative services on our behalf (referred to as indirect employees). These charges were either directly identifiable or allocated to our operations. Direct charges included goods and services provided by Williams at our request. Allocated general corporate costs were based on our relative usage of the service or on a three-factor formula, which considers revenues; properties and equipment; and payroll. Our share of direct general and administrative expenses and our share of allocated general corporate expenses was reflected in general and administrative expense in the accompanying Consolidated Statements of Operations. In management’s estimation, the allocation methodologies used were reasonable and resulted in a reasonable allocation to us of our costs of doing business incurred by Williams.
 
Other arrangements with Williams or its affiliates
We also have operating activities with Williams Partners and another Williams subsidiary. Beginning January 1, 2012, Williams and its subsidiaries were no longer related parties, therefore only amounts related to 2011 are disclosed as related parties. For 2011, the following were considered related party transactions. Our revenues include revenues from the following types of transactions:
Sales of NGLs related to our production to Williams Partners at market prices at the time of sale and included within our oil and gas sales revenues; and
Sales to Williams Partners and another Williams subsidiary of natural gas procured by WPX Energy Marketing for those companies’ fuel and shrink replacement at market prices at the time of sale and included in our gas management revenues.
Our costs and operating expenses include the following services provided by Williams Partners:
Gathering, treating and processing services under several contracts for our production primarily in the San Juan and Piceance Basins; and
Pipeline transportation for both our oil and gas sales and gas management activities which included commitments totaling $401 million at December 31, 2011.
We have managed a transportation capacity contract for Williams Partners. To the extent the transportation is not fully utilized or does not recover full-rate demand expense, Williams Partners reimburses us for these transportation costs. These reimbursements to us totaled approximately $11 million for the year ended December 31, 2011, and are included in gas management revenues. We signed an agreement with Williams Partners under which these contracts were assigned to them effective May 1, 2012.
Prior to December 1, 2011, we participated in Williams’ centralized approach to cash management and the financing of its businesses. Daily cash activity from our domestic operations was transferred to or from Williams on a regular basis and was recorded as increases or decreases in the balance due under unsecured promissory notes we had in place with Williams through June 30, 2011, at which time the notes were cancelled by Williams.
The amount due to Williams at the time of cancellation was $2.4 billion and is reflected as an increase in owner’s net investment. Through fourth-quarter 2011, an additional $162 million was cancelled and reflected as an increase in owner’s net investment. The notes reflected interest based on Williams’ weighted average cost of debt and such interest was added monthly to the note principle. The interest rate for the notes payable to Williams was 8.08 percent at June 30, 2011.
On August 25, 2011, we entered into a 10.5 year lease for our present headquarters office with Williams Headquarters Building Company, a direct subsidiary of Williams. We estimate the annual rent payable by us under the lease to be approximately $4 million per year.
Below is a summary for 2011 of the transactions with Williams or its affiliates (including amounts in discontinued operations) discussed above:
 
 
2011
 
(Millions)
Product revenues—sales of NGLs to Williams Partners
$
258

Gas management revenues—sales of natural gas for fuel and shrink to Williams Partners and another Williams subsidiary
586

Lease and facility operating expenses from Williams-direct employee salary and benefit costs
21

Gathering, processing and transportation expense from services with Williams Partners:
 
Gathering and processing
298

Transportation
44

General and administrative from Williams:
 
Direct employee salary and benefit costs
111

Charges for general and administrative services
62

Allocated general corporate costs
62

Other
16

Interest expense on notes payable to Williams
96

Investment Income and Other
Investment Income and Other
Investment Income and Other
Investment income
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
 
 
 
 
 
 
Equity earnings- Petrolera Entre Lomas S.A.
$
19

 
$
26

 
$
20

Equity earnings- other
4

 
4

 
4

Impairment of equity method investment in Appalachian Basin
(20
)
 

 

Other
2

 

 
2

Total investment income and other
$
5

 
$
30

 
$
26



The nature of the assets in the equity method investment in the Appalachian Basin is such that under normal circumstances an entity would capitalize and evaluate the assets as part of its producing properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing properties that utilize the assets of the entity. As a result of the 2013 impairment of the producing properties in the Appalachian Basin, we recorded an impairment of the equity method investment in 2013.
Investments
 
December 31,
 
2013
 
2012
 
(Millions)
Petrolera Entre Lomas S.A.—40.8%
$
125

 
$
109

Other
20

 
36

 
$
145

 
$
145


Petrolera Entre Lomas S.A. operates several development concessions in South America. Other is comprised of investments in miscellaneous gas gathering interests in the United States.
Dividends and distributions received from companies accounted for by the equity method were $7 million, $12 million and $17 million in 2013, 2012 and 2011, respectively.
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
 The following table summarizes the calculation of earnings per share.
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
$
1,185

 
$
(245
)
 
$
(160
)
Basic weighted-average shares
200.5

 
198.8

 
197.1

Diluted weighted-average shares
200.5

 
198.8

 
197.1

Earnings (loss) per common share from continuing operations:
 
 
 
 
 
Basic
$
(5.91
)
 
$
(1.23
)
 
$
(0.81
)
Diluted
$
(5.91
)
 
$
(1.23
)
 
$
(0.81
)

The following table includes amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidiltive due to our loss from continuing operations attributable to WPX Energy, Inc.
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
Weighted-average nonvested restricted stock units and awards
2.5

 
1.9

 
2.9

Weighted-average stock options
1.1

 
1.0

 
1.2


On December 31, 2011, 197.1 million shares of our common stock were distributed to Williams’ shareholders in conjunction with our spin-off. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount of common stock to be outstanding as of the beginning of 2011 in the calculation of basic and diluted weighted average shares.
The table below includes information related to stock options that were outstanding at December 31, 2013 and 2012 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.
 
 
 
 
 
2013
 
2012
Options excluded (millions)
0.4

 
1.3

Weighted-average exercise price of options excluded
$
20.24

 
$
18.17

Exercise price range of options excluded
$20.21 - $20.97

 
$16.46  - $20.97

Fourth quarter weighted-average market price(a)
$
19.97

 
$
16.15

 __________
(a)
Our stock began trading on the New York Stock Exchange on January 3, 2012; therefore, a fourth quarter weighted-average market price is not available for 2011.
Asset Sales, Impairments and Exploration Expenses
Asset Sales, Impairments and Exploration Expenses
Asset Sales, Impairments and Exploration Expenses
In 2013, we recorded a total of $1.4 billion in impairment charges of which $1,055 million is recorded as a separate line on the Consolidated Statements of Operations, $317 million is included in exploration expense and $20 million is included in investment income and other (see Note 4). These impairments are discussed further in the sections below.
Impairments and Asset Sales
The following table presents a summary of significant gains or losses reflected in impairment of producing properties and costs of acquired unproved reserves, gain on sale, and other—net within costs and expenses. These significant adjustments are primarily associated with our domestic operations.
 
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
Impairment of producing properties and costs of acquired unproved reserves(a)
$
1,055

 
$
225

 
$
367

Gain on sale of Powder River Basin deep rights leasehold
$
36

 
$

 
$

Net gain on sales of other assets
$
4

 
$
4

 
$
1


 __________
(a)
Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.
As a result of declines in forward natural gas prices primarily during the fourth-quarter 2013 as compared to forward prices as of December 31, 2012, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves. Accordingly, we recorded the following impairments during 2013:
$772 million impairment in the fourth quarter of proved producing oil and gas properties in the Appalachian Basin;
$192 million impairment in the fourth quarter including $107 million of proved producing oil and gas properties and $85 million of the capitalized costs of acquired unproved reserves in the Powder River Basin;
$88 million impairment in the Piceance Basin including impairments of capitalized costs of acquired unproved reserves of $19 million and $69 million in the third and fourth quarters, respectively, in the Kokopelli area; and,
$3 million impairment in the fourth quarter on property in Colombia.
As a result of declines in forward natural gas and natural gas liquids prices during 2012 as compared to forward natural gas and natural gas liquids prices as of December 31, 2011, we performed impairment assessments of our proved producing properties and capitalized cost of acquired unproved reserves during 2012. Accordingly, we recorded impairments of $48 million of proved producing oil and gas properties in the Green River Basin. Additionally, we recorded a total of $102 million and $75 million in impairments of capitalized costs of acquired unproved reserves primarily in the Powder River Basin and Piceance Basin, respectively. Our impairment analyses included an assessment of undiscounted and discounted future cash flows, which considered information obtained from drilling, other activities and reserves quantities (see Note 15).
As part of our assessment for impairments primarily resulting from declining forward natural gas prices during the fourth-quarter 2011, we recorded a $276 million impairment of proved producing oil and gas properties in the Powder River Basin (see Note 15). Additionally, we recorded a $91 million impairment of our capitalized cost of acquired unproved reserves in the Powder River Basin.
Our impairment analyses included an assessment of undiscounted (except for the costs of acquired unproved reserves) and discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (see Note 15).
In October 2013, we completed the sale of deep rights leasehold on approximately 140,000 net acres in the Powder River Basin for $36 million. This sale did not include our producing coal bed methane assets in the Powder River Basin.
 
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
Geologic and geophysical costs
$
22

 
$
21

 
$
18

Dry hole costs
7

 
4

 
13

Unproved leasehold property impairment, amortization and expiration
402

 
58

 
95

Total exploration expenses
$
431

 
$
83

 
$
126


Dry hole costs in 2011 reflect an $11 million dry hole expense in connection with a Marcellus Shale well in Columbia County, Pennsylvania.
Unproved leasehold impairment, amortization and expiration in 2013 includes a $317 million impairment to estimated fair values of Appalachia leasehold, while 2011 includes a $50 million write-off of leasehold costs associated with certain portions of our Columbia County, Pennsylvania acreage that we did not plan to develop. The $317 million impairment is associated with our impairment of the producing properties in the Appalachian Basin.
Properties and Equipment
Properties and Equipment
Properties and Equipment
Properties and equipment is carried at cost and consists of the following:
 
 
Estimated
Useful
Life(a)
(Years)
 
December 31,
 
2013
 
2012
 
 
 
(Millions)
Proved properties
(b)
 
$
11,476

 
$
11,267

Unproved properties
(c)
 
423

 
1,156

Gathering, processing and other facilities
15-25
 
225

 
247

Construction in progress
(c)
 
382

 
497

Other
3-40
 
180

 
172

Total properties and equipment, at cost
 
 
12,686

 
13,339

Accumulated depreciation, depletion and amortization
 
 
(5,445
)
 
(4,923
)
Properties and equipment—net
 
 
$
7,241

 
$
8,416

__________
(a)
Estimated useful lives are presented as of December 31, 2013.
(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 Appalachian Basin and the Williston Basin and costs of acquired unproved reserves in the Powder River and Piceance Basins.
Construction in progress includes $15 million in 2013 and $44 million in 2012 related to wells located in the Powder River Basin. In order to produce gas from the coal seams, an extended period of dewatering is required prior to natural gas production. Additionally, construction in progress in 2013 includes $24 million related to exploratory well costs pending the determination of proved reserves. 
Asset Retirement Obligations
Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.
A rollforward of our asset retirement obligations for the years ended 2013 and 2012 is presented below.
 
 
2013
 
2012
 
(Millions)
Balance, January 1
$
321

 
$
289

Liabilities incurred during the period
14

 
19

Liabilities settled during the period
(11
)
 
(7
)
Estimate revisions
17

 
(1
)
Accretion expense(a)
23

 
21

Balance, December 31
$
364

 
$
321

Amount reflected as current
$
6

 
$
5

__________
(a)
Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
Estimate revisions in 2013 are primarily associated with increases in anticipated plug and abandonment costs.
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable
 
December 31,
 
2013
 
2012
 
(Millions)
Trade
$
213

 
$
209

Accrual for capital expenditures
237

 
126

Royalties
130

 
106

Cash overdrafts
35

 
34

Other
37

 
34

 
$
652

 
$
509


Accrued and other current liabilities
 
December 31,
 
2013
 
2012
 
(Millions)
Taxes other than income taxes
$
41

 
$
54

Accrued interest
43

 
42

Compensation and benefit related accruals
52

 
52

Other, including other loss contingencies
54

 
53

 
$
190

 
$
201

Debt and Banking Arrangements
Debt and Banking Arrangements
Debt and Banking Arrangements
As of the indicated dates, our debt consisted of the following:
 
 
December 31,
 
2013(a)
 
2012 (a)
 
(Millions)
5.250% Senior Notes due 2017
$
400

 
$
400

6.000% Senior Notes due 2022
1,100

 
1,100

Credit facility agreement
410

 

Apco
8

 
8

Other
1

 
2

Total debt
$
1,919

 
$
1,510

Less: Current portion of long-term debt
3

 
2

Total long-term debt
$
1,916

 
$
1,508

__________
(a)
Interest paid on debt totaled $91 million and $58 million for 2013 and 2012, respectively.
Senior Notes
In November 2011, we issued $1.5 billion in face value Senior Notes (“the Notes”). The Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the Notes were approximately $1.481 billion after deducting the initial purchasers’ discounts and our offering expenses. We retained $500 million of the net proceeds from the issuance of the Notes and distributed the remainder of the net proceeds from the issuance of the Notes, approximately $981 million, to Williams in connection with the Contribution.
Optional Redemption. We have the option, prior to maturity, in the case of the 2017 notes, and prior to October 15, 2021 (which is three months prior to the maturity date of the 2022 notes) in the case of the 2022 notes, to redeem all or a portion of the Notes of the applicable series at any time at a redemption price equal to the greater of (i) 100% of their principal amount and (ii) the discounted present value of 100% of their principal amount and remaining scheduled interest payments, in either case plus accrued and unpaid interest to the redemption date. We also have the option at any time on or after October 15, 2021, to redeem the 2022 notes, in whole or in part, at a redemption price equal to 100% of their principal amount, plus accrued and unpaid interest thereon to the redemption date.
Change of Control. If we experience a change of control (as defined in the indenture governing the Notes) accompanied by a rating decline with respect to a series of Notes, 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 indenture 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 indenture also requires us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indenture. However, these limitations and requirements will be subject to a number of important qualifications and exceptions. The indenture does 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 indenture 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.
Notes Registration. In June 2012, we completed an exchange offer whereby we exchanged our privately-placed Notes for like principal amounts of registered 5.250% Senior Notes due 2017 and 6.000% Senior Notes due 2022. The exchange offer fulfilled our obligations under the registration rights agreement that we entered into as part of the November 2011 issuance.
Credit Facility Agreement
During 2011, we entered into a new $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. As of December 31, 2013, the weighted average variable interest rate was 2.27 percent on the $410 million outstanding under the Credit Facility Agreement. Subsequent to December 31, 2013, we have borrowed an additional net amount of $195 million under the Credit Facility Agreement.
Interest on borrowings under the Credit Facility Agreement will be payable at rates per annum equal to, at our option: (1) a fluctuating base rate equal to the Alternate Base Rate plus the Applicable Rate, or (2) a periodic fixed rate equal to LIBOR plus the Applicable Rate. The Alternate Base Rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Applicable Rate changes depending on which interest rate we select and our credit rating. Additionally, we will be required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility Agreement.
Under the Credit Facility Agreement, prior to the occurrence of the Investment Grade Date (as defined below), we will be required to maintain a ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness (each as defined in the Credit Facility Agreement) of at least 1.50 to 1.00. Net present value is determined as of the end of each fiscal year and reflects the present value, discounted at 9 percent, of projected future cash flows of domestic proved oil and gas reserves (such cash flows are adjusted to reflect the impact of hedges, our lenders’ commodity price forecasts, and, if necessary, to include only a portion of our reserves that are not proved developed producing reserves). Additionally, the ratio of debt to capitalization (defined as net worth plus debt) will not be permitted to be greater than 60%. We were in compliance with our debt covenant ratios as of December 31, 2013. Investment Grade Date means the first date on which our long-term senior unsecured debt ratings are BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.
The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of our subsidiaries to incur indebtedness, make investments, loans or advances and enter into certain hedging agreements; our ability to merge or consolidate with any person or sell all or substantially all of our assets to any person, enter into certain affiliate transactions, make certain distributions during the continuation of an event of default and allow material changes in the nature of our business. In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors.
The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to us occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of any loans outstanding under the Credit Facility Agreement at the time, in addition to the exercise of other rights and remedies available.
Letters of Credit
In addition to the Notes and Credit Facility Agreement, WPX has entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At December 31, 2013 a total of $361 million in letters of credit have been issued.
Apco
Apco had a loan agreement with a financial institution for a $10 million bank line of credit. As of December 31, 2013, Apco had borrowed $8 million under this banking agreement. Principal amounts will be repaid in installments through 2016. This debt agreement contains covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, purchase or sell assets outside the ordinary course of business, and incur additional debt.
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
The provision (benefit) for income taxes from continuing operations includes:
 
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
Provision (benefit):
 
 
 
 
 
Current:
 
 
 
 
 
Federal
$
(29
)
 
$
48

 
$
49

State
1

 
3

 
7

Foreign
18

 
14

 
10

 
(10
)
 
65

 
66

Deferred:
 
 
 
 
 
Federal
(608
)
 
(162
)
 
(139
)
State
(51
)
 
(13
)
 
(1
)
Foreign
14

 
(1
)
 

 
(645
)
 
(176
)
 
(140
)
Total provision (benefit)
$
(655
)
 
$
(111
)
 
$
(74
)

 
Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
Provision (benefit) at statutory rate
$
(646
)
 
$
(120
)
 
$
(79
)
Increases (decreases) in taxes resulting from:
 
 
 
 
 
State income taxes (net of federal benefit)
(110
)
 
(10
)
 
(5
)
State income change in valuation allowance (net of federal benefit)
80

 
3

 

Effective state income tax rate change (net of federal benefit)
(3
)
 

 
9

Alternative minimum tax credits

 
11

 

Argentina capital tax (net of federal benefit)
10

 

 

Foreign operations
5

 
4

 

Other
9

 
1

 
1

Provision (benefit) for income taxes
$
(655
)
 
$
(111
)
 
$
(74
)

Significant components of deferred tax liabilities and deferred tax assets are as follows:
 
December 31,
 
2013
 
2012
 
(Millions)
Deferred tax liabilities:
 
 
 
Properties and equipment
$
963

 
$
1,652

Other, net
36

 
19

Total deferred tax liabilities
999

 
1,671

Deferred tax assets:
 
 
 
Accrued liabilities and other
176

 
176

Alternative minimum tax credits
76

 
99

Loss carryovers
89

 
31

Other
21

 

Total deferred tax assets
362

 
306

Less: valuation allowance
102

 
19

Total net deferred tax assets
260

 
287

Net deferred tax liabilities
$
739

 
$
1,384


Net cash refunds for domestic income taxes were $26 million in 2013 while net cash payments were $40 million and $10 million in 2012 and 2011, respectively. Additionally, payments made directly to foreign taxing authorities were $14 million, $11 million and $10 million in 2013, 2012 and 2011, respectively.
As of December 31, 2013, the Company has approximately $114 million of federal net operating loss ("NOL") carryovers which begin expiring after 2033, as well as approximately $825 million of state NOL carryovers, primarily in Pennsylvania, of which more than 90 percent expire after 2029.
Income (loss) from continuing operations before income taxes includes foreign income of $50 million, $52 million and $40 million in 2013, 2012 and 2011, respectively. This income is attributable to our 69 percent investment in Apco, a Cayman Islands corporation with operations in Argentina and Colombia. The statutory income tax rate in Argentina is 35 percent while the rate in Colombia is 25 percent with an additional 9 percent for certain items.
We have recorded valuation allowances against deferred tax assets attributable primarily to our operations in Pennsylvania and Apco's operations in Colombia. In determining whether to record a valuation allowance we assess available positive and negative evidence to evaluate whether it is more likely than not that we will realize the benefit of a deferred tax asset. We have historically generated NOLs in Pennsylvania where we file separately, plus they have an annual limitation that impacts our ability to use NOL carryovers to reduce future taxable income in Pennsylvania. Apco has historically generated NOLs from its Colombia operations. As a result of our assessment of available evidence, valuation allowances were recorded to reduce recognized tax assets, net of federal benefit, to an amount that will more likely than not be realized by the Company.
Undistributed earnings of Apco at December 31, 2013, excluding amounts related to Apco's equity investment in Petrolera Entre Lomas S.A. ("Petrolera") totaled approximately $76 million. No provision for deferred U.S. income taxes has been made for those undistributed earnings because it is our intent to reinvest Apco's earnings in its operation in Argentina and Colombia. U.S income taxes have been accrued as required by GAAP, however, to the extent book basis exceeds tax basis in Apco's equity investment in Petrolera.
In September 2013, the Argentine government enacted tax reform legislation related to dividends and capital gains which will apply to the Argentine operations of Apco. The new 10 percent dividend tax will be accrued by Apco when dividends are paid by its Argentine investments in future periods. The capital gains tax applies to the sale of Argentine securities by a non-Argentine resident, such as Apco, making such sales subject to an effective 13.5 percent tax on the gross proceeds. As a result, Apco recorded approximately $14 million of foreign deferred tax expense during third quarter 2013 for the excess book basis over tax basis in its equity investment in Petrolera, of which approximately $12 million relates to basis differences that occurred prior to 2013. This accrual was partially offset by approximately $4 million of U.S. deferred tax benefit recorded by WPX related to the additional Argentine tax.
Employee share-based compensation attributable to the exercise of stock options and vesting of restricted stock is deductible by us for tax purposes. To the extent these tax deductions exceed the previously accrued deferred tax benefit for these items the additional tax benefit is not recognized under GAAP until the deduction reduces current taxes payable. Since the additional tax benefit does not reduce our current taxes payable for 2013, these tax benefits are not included in the Company’s loss carryovers deferred tax asset. The additional tax benefit deductible for tax purposes but not included in our loss carryovers deferred tax asset as of December 31, 2013 totaled $7 million.
Through the effective date of the spin-off, December 31, 2011, the Company’s domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision for 2011 has been calculated on a separate return basis for the Company and its consolidated subsidiaries, except for certain adjustments such as alternative minimum tax calculated at the consolidated level by Williams. Effective with the spin-off, Williams and the Company entered into a tax sharing agreement which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off.
In connection with the spin-off, alternative minimum tax credits were estimated and allocated between Williams and the Company effective December 31, 2011. This resulted in the allocation to the Company of a $98 million deferred tax asset with a corresponding increase to additional paid-in-capital. Subsequent to the spin-off, Williams notified the Company of certain corrections that resulted in $15 million of reductions in the alternative minimum tax credit allocated to the Company of which $11 million is a reduction of the benefit for income taxes in 2012.
Pursuant to our tax sharing agreement with Williams, we will remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. During the third quarter of 2012, Williams finalized settlements with the IRS for 2009 and 2010. We were recently notified that the IRS has commenced an audit of Williams' 2011 consolidated tax filing. The statute of limitations for most states expires one year after expiration of the IRS statute. Income tax returns for Apco's operations in Argentina are open to audit for the 2006 to 2013 tax years.
The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.
As of December 31, 2013, the Company has no significant unrecognized tax benefits. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with a domestic or international matter will result in a significant increase or decrease of an unrecognized tax benefit.
Contingent Liabilities and Commitments
Contingent Liabilities and Commitments
Contingent Liabilities and Commitments
Royalty litigation
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs' proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We are in the process of conducting an accounting under that standard. However, we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law.
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, fraud, fraud concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs seek monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter has been removed to the United States District Court for New Mexico. 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, violation of the New Mexico Oil and Gas Proceeds Payment Act and seek declaratory judgment, accounting and injunction. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR's guidance provides its view as to how much of a producer's bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR's assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR's predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From January 2007 through December 2013, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $106 million.
Environmental matters
The Environmental Protection Agency (“EPA”), other federal agencies, and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, 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 the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending or threatened litigation described below relating to the 2000-2001 California energy crisis and the reporting of certain natural gas-related information to trade publications.
California energy crisis
Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the Federal Energy Regulatory Commission (“FERC”). We have entered into settlements with the State of California (“State Settlement”), major California utilities (“Utilities Settlement”) and others that substantially resolved each of these issues with these parties.
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We currently have a settlement agreement in principle with certain California utilities aimed at eliminating and substantially reducing this exposure. Once finalized, the settlement agreement will also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement will resolve most, if not all, of our legal issues arising from the 2000-2001 California energy crisis. With respect to these matters, amounts accrued are not material to our financial position. 
Certain other issues also remain open at the FERC and for other nonsettling parties.
Reporting of natural gas-related information to trade publications
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order.
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion on the Western States Antitrust Litigation.  The panel held that the Natural Gas Act does not preempt the plaintiffs' state antitrust claims, reversing the summary judgment entered in favor of the defendants.  The panel further held that the district court did not abuse its discretion in denying the plaintiffs' motions for leave to amend complaints. Defendants' filed a petition for writ of certiorari with the U.S. Supreme Court. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
At December 31, 2013, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
In connection with the separation from Williams, we have 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, 2013 and December 31, 2012, the Company had accrued approximately $16 million and $18 million, respectively, for loss contingencies associated with royalty litigation and other contingencies. In 2013, we accrued and settled certain royalty litigation matters for approximately $8 million. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
Commitments
As part of managing our commodity price risk, we utilize contracted pipeline capacity to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2013 are as follows:
 
 
(Millions)
2014
$
224

2015
219

2016
197

2017
178

2018
167

Thereafter
578

 
 

Total
$
1,563


We also have certain commitments (including commitments to an equity investee), primarily for natural gas gathering and treating services and well completion services, which total $389 million over approximately six years.
We hold a long-term obligation to deliver on a firm basis 200,000 MMBtu per day of natural gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance Basin. This obligation expires in November 2014.
In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Shale) at market prices from the same third party. Purchases under the 12-year contract began in the first quarter of 2012. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.
Future minimum annual rentals under noncancelable operating leases as of December 31, 2013, are payable as follows:
 
(Millions)
2014
$
58

2015
50

2016
29

2017
8

2018
7

Thereafter
22

 
 
Total
$
174


Total rent expense, excluding amounts capitalized, was $27 million, $20 million and $12 million in 2013, 2012 and 2011, 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
Subsequent to spin-off
On January 1, 2012, several new plans became effective for us including a defined contribution plan. WPX matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution of equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40. Total contributions to this plan were $16 million and $6 million for 2013 and 2012, respectively. Approximately $11 million and $10 million were included in accrued and other current liabilities at December 31, 2013 and December 31, 2012, respectively, related to the non-matching annual employer contribution.
Prior to spin-off
Through the spin-off date, certain benefit costs associated with direct employees who supported our operations were determined based on a specific employee basis and were charged to us by Williams as described below. These pension and post retirement benefit costs included amounts associated with vested participants who are no longer employees. As described in Note 3, Williams also charged us for the allocated cost of certain indirect employees of Williams who provided general and administrative services on our behalf. Williams included an allocation of the benefit costs associated with these Williams employees based upon Williams’ determined benefit rate, not necessarily specific to the employees providing general and administrative services on our behalf. As a result, the information described below is limited to amounts associated with the direct employees that supported our operations.
For the periods presented, we were not the plan sponsor for these plans. Accordingly, our Consolidated Balance Sheets do not reflect any assets or liabilities related to these plans.
Pension plans
Williams is the sponsor of noncontributory defined benefit pension plans that provide pension benefits for its eligible employees. Pension expense charged to us by Williams for 2011 totaled $8 million.
Other postretirement benefits
Williams is the sponsor of subsidized retiree medical and life insurance benefit plans (“other postretirement benefits”) that provide benefits to certain eligible participants, generally including employees hired on or before December 31, 1991, and other miscellaneous defined participant groups. Other postretirement benefit expense charged to us by Williams for 2011 totaled less than $1 million.
Defined contribution plan
Williams also is the sponsor of a defined contribution plan that provides benefits to certain eligible participants and charged us compensation expense of $4 million in 2011 for Williams’ matching contributions to this plan.
Stock-Based Compensation
Stock-Based Compensation
Stock-Based Compensation
WPX Energy, Inc. 2011 Incentive Plan
Subsequent to the spin-off, we have an equity incentive plan (“2011 Incentive Plan”) and an employee stock purchase plan (“ESPP”). The 2011 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. The number of shares of common stock authorized for issuance pursuant to all awards granted under the 2011 Incentive Plan is 11 million shares. The 2011 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 2011 Incentive Plan.
The ESPP allows domestic employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1 million shares, subject to adjustment for stock splits and similar events. The first offering under the ESPP commenced on March 1, 2012 and ended on June 30, 2012. Subsequent offering periods are from January through June and from July through December. Employees purchased 117 thousand shares at an average price of $14.33 per share during 2013.
The Williams Companies, Inc. Incentive Plan
Certain of our direct employees participated in The Williams Companies, Inc. 2007 Incentive Plan, which provides for Williams common-stock-based awards to both employees and Williams’ nonmanagement directors. The plan permits the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets.
Through the date of spin-off, we were charged by Williams for stock-based compensation expense related to our direct employees. Williams also charged us for the allocated costs of certain indirect employees of Williams (including stock-based compensation) who provided general and administrative services on our behalf. However, information included in this note is limited to stock-based compensation associated with the direct employees for 2011. See Note 3 for total costs charged to us by Williams.
Williams’ Compensation Committee determined that all outstanding Williams stock-based compensation awards, whether vested or unvested, other than outstanding options issued prior to January 1, 2006 (the “Pre-2006 Options”), be converted into awards with respect to shares of common stock of the company that continues to employ the holder following the spin-off. The Pre-2006 Options (whether held by our employees or other Williams employees) converted into options for both Williams and WPX common stock following the spin-off, in the same ratio as is used in the distribution of WPX common stock to holders of Williams common stock. The number of shares underlying each such award (including the Pre-2006 Options) and, with respect to options (including the Pre-2006 Options), the per share exercise price of each award was adjusted to maintain, on a post-spin-off basis, the pre-spin-off intrinsic value of each award.
Employee stock-based awards
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.
Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
Restricted stock units are generally valued at fair value on the grant date and generally vest over three years . Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
Total stock-based compensation expense (including amount charged to us by Williams) reflected in general and administrative expense for the years ended December 31, 2013, 2012 and 2011 was $31 million, $28 million and $18 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2013 was $41 million. This amount is comprised of $1 million related to stock options and $40 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 2.0 years.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2013.
  
WPX Plan
Stock Options
Options
 
Weighted-
Average
Exercise
Price
 
Aggregate
Intrinsic
Value
 
(Millions)
 
 
 
(Millions)
Outstanding at December 31, 2012(a)
4.1

 
$
12.68

 
$
14

Granted
0.4

 
$
14.41

 
 
Exercised
(0.4
)
 
$
8.86

 
 
Forfeited

 
$
16.46

 
 
Expired

 
$
19.26

 
 
Outstanding at December 31, 2013(a)
4.1

 
$
13.27

 
$
29

Exercisable at December 31, 2013
3.2

 
$
12.62

 
$
25

__________
(a)
Includes approximately 344 thousand shares held by Williams’ employees at a weighted average price of $9.24 per share at December 31, 2013 and 598 thousand shares held by Williams' employees at a weighted average price of $8.48 per share at December 31, 2012.
The total intrinsic value of options exercised during the years ended December 31, 2013, 2012 and 2011 was $5 million, $5 million and $7 million, respectively.
The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2013.
 
WPX Plan
 
Stock Options Outstanding
 
Stock Options Exercisable
Range of Exercise Prices
Options
 
Weighted-
Average
Exercise
Price
 
Weighted-
Average
Remaining
Contractual
Life
 
Options
 
Weighted-
Average
Exercise
Price
 
Weighted-
Average
Remaining
Contractual
Life
 
(Millions)
 
 
 
(Years)
 
(Millions)
 
 
 
(Years)
$5.50 to $6.02
0.8

 
$
5.95

 
4.5
 
0.8

 
$
5.95

 
4.5
$9.08 to $11.75
0.9

 
$
11.34

 
4.3
 
0.9

 
$
11.34

 
4.3
$12.00 to $15.67
1.1

 
$
14.45

 
5.4
 
0.7

 
$
14.47

 
2.9
$16.46 to $20.97
1.3

 
$
18.17

 
6.4
 
0.8

 
$
18.48

 
5.9
Total
4.1

 
$
13.27

 
5.3
 
3.2

 
$
12.62

 
4.5

The estimated fair value at date of grant of options for our common stock and date of conversion for WPX awards in each respective year, using the Black-Scholes option pricing model, is as follows:
 
WPX Plan
 
2013
 
2012
 
2011
Weighted-average grant date fair value of options granted
$
6.04

 
$
7.79

 
$

Weighted-average conversion date fair value options granted
 
 
 
 
$
8.48

Weighted-average assumptions:
 
 
 
 
 
Dividend yield

 

 

Volatility
42.8
%
 
43.8
%
 
45.0
%
Risk-free interest rate
1.06
%
 
1.17
%
 
0.38
%
Expected life (years)
6.0

 
6.0

 
2.8


For 2013 and 2012, we determined that the Williams stock option grant data was not relevant for valuing WPX options; therefore the Company used the SEC simplified method. The expected volatility is based primarily on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life is assumed based on the SEC simplified method.
For 2011, the weighted average fair value is a component of the intrinsic value calculation at spin-off. The expected volatility yield is based on the historical volatility of comparable peer group stocks. The risk free interest rate is based on the U.S. Treasury Constant Maturity rates as of the modification date. The expected life of the options is based over the remaining option term.
Cash received from stock option exercises was $4 million and $2 million during 2013 and 2012, respectively.
Nonvested Restricted Stock Units
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2013.
 
WPX Plan
Restricted Stock Units
Shares
 
Weighted-
Average
Fair Value(a)
 
(Millions)
 
 
Nonvested at December 31, 2012
4.8

 
$
16.45

Granted
2.2

 
$
14.97

Forfeited
(0.2
)
 
$
16.61

Vested
(1.6
)
 
$
11.27

Nonvested at December 31, 2013
5.2

 
$
16.97

__________
(a)
Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.
Other restricted stock unit information
 
WPX Plan
 
Williams Plan
 
2013
 
2012
 
2011
Weighted-average grant date fair value of restricted stock units granted during the year, per share
$
14.97

 
$
17.35

 
$
27.74

Total fair value of restricted stock units vested during the year (millions)
$
18

 
$
14

 
$
10


Performance-based shares granted represent 17 percent of nonvested restricted stock units outstanding at December 31, 2013. 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.
Stockholders' Equity
Stockholders' Equity
Stockholders’ Equity
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 were declared or paid for 2013, 2012 or 2011. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
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.
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 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 and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
December 31, 2013
 
December 31, 2012
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
 
(Millions)
 
 
 
(Millions)
Energy derivative assets
$
30

 
$
26

 
$
1

 
$
57

 
$
20

 
$
38

 
$
2

 
$
60

Energy derivative liabilities
$
83

 
$
38

 
$
1

 
$
122

 
$
11

 
$
1

 
$
3

 
$
15

Total debt(a)
$

 
$
1,945

 
$

 
$
1,945

 
$

 
$
1,617

 
$

 
$
1,617

__________
(a)
The carrying value of total debt, excluding capital leases, was $1,918 million and $1,508 million as of December 31, 2013 and 2012, respectively.
Energy derivatives include commodity based exchange-traded contracts and 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, and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the net fair value of our derivatives portfolio expiring in the next 24 months. 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 and documented on a monthly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at December 31, 2013, consist primarily of natural gas index transactions that are used to manage our physical requirements.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the years ended December 31, 2013 or 2012. During the period ended March 31, 2011, certain NGL swaps that originated during the first quarter of 2011 were transferred from Level 3 to Level 2. Prior to March 31, 2011, these swaps were considered Level 3 due to a lack of observable third-party market quotes. Due to an increase in exchange-traded transactions and greater visibility from OTC trading, we transferred these instruments to Level 2.
The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
 
Years ended December 31,
 
2013
Net Energy
Derivatives
 
2012
Net Energy
Derivatives
 
2011
Net Energy
Derivatives
 
(Millions)
Beginning balance
$
(1
)
 
$
1

 
$
1

Realized and unrealized gains (losses):
 
 
 
 
 
Included in income (loss) from continuing operations
(2
)
 
3

 
15

Included in other comprehensive income (loss)

 

 

Purchases, issuances, and settlements
3

 
(5
)
 
(12
)
Transfers out of Level 3

 

 
(3
)
Ending balance
$

 
$
(1
)
 
$
1

Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 31
$
(1
)
 
$
(1
)
 
$
1


Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Consolidated Statements of Operations.
For the year ending December 31, 2011, the entire $12 million reduction to level 3 fair value measurements are settlements.
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 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 natural gas-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 natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, future natural gas liquids prices, 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 each of the three years ended December 31, 2013, our assessments 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 years ended December 31,
 
 
 
2013
 
 
 
2012
 
 
 
2011
 
 
 
(Millions)
 
 
Impairments:
 
 
 
 
 
 
 
 
 
 
 
Producing properties and costs of acquired unproved reserves (Note 6)
1,055

 
(a) 
 
225

 
(b) 
 
367

 
(c) 
Unproved leasehold
317

 
(a) 
 

 
 
 

 
 
Equity method investment (Note 4)
20

 
 
 

 
 
 

 
 
 
$
1,392

 
 
 
$
225

 
  
 
$
367

 
  
__________
(a)
As a result of our impairment assessment in 2013, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2013 was estimated to be approximately $365 million
$792 million impairment charge related to natural gas producing properties and an equity method investment in the Appalachian Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 299 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.60 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
$317 million impairment charge on our unproved leasehold acreage in the Appalachian Basin as a result of the impairment of the producing properties. Significant assumptions included estimates of the value per acre based on our recent transactions and those transactions observed in the market.
$107 million impairment charge related to natural gas producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 294 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.53 per Mcfe for natural gas (adjusted for locational differences), and an after-tax discount rate of 11 percent.
$88 million impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
$85 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 15 percent and 18 percent for probable and possible reserves, respectively.
(b)
As a result of our impairment assessments in 2012, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2012 was estimated to be approximately $351 million.
$102 million and $75 million of impairment charges related to acquired unproved reserves in the Powder River Basin and Piceance Basin, respectively. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
$48 million impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 29 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $5.87 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.
(c)
As a result of our impairment assessments in 2011, we recorded the following significant impairment charges for which the fair value measured for these properties at December 31, 2011, was estimated to be approximately $546 million.
$276 million impairment charge related to natural gas-producing properties in the Powder River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent. 
$91 million impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
Derivatives and Concentration of Credit Risk
Derivatives and Concentration of Credit Risk
Derivatives and Concentration of Credit Risk
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas, oil and natural gas liquids attributable to commodity price risk. Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we entered into commodity derivative contracts that continued to serve as economic hedges but were not designated as cash flow hedges for accounting purposes as we elected not to utilize this method of accounting on new derivatives instruments. Remaining commodity derivatives recorded at December 31, 2011 that were designated as cash flow hedges were fully realized by the end of the first quarter of 2013.
We produce, buy and sell natural gas, crude oil and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas, crude oil and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions.
We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation and storage contracts economically hedge the expected cash flows generated by those agreements.
The following table sets forth the derivative notional volumes that are economic hedges of production volumes as well as notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, both which are included in our commodity derivatives portfolio as of December 31, 2013.
Derivatives related to production
Commodity
 
Period
 
Contract Type(a)
 
Location
 
Notional Volume(b)
 
Weighted Average
Price(c)
Crude Oil
 
2014
 
Fixed Price Swaps
 
WTI
 
(13,243
)
 
$
94.82

Crude Oil
 
2014
 
Basis Swaps
 
Brent
 
(4,463
)
 
$
9.64

Natural Gas
 
2014
 
Fixed Price Swaps
 
Henry Hub
 
(315
)
 
$
4.19

Natural Gas
 
2014
 
Swaptions
 
Henry Hub
 
(50
)
 
$
4.24

Natural Gas
 
2014
 
Costless Collars
 
Henry Hub
 
(165
)
 
$ 4.01 - 4.64
Natural Gas
 
2014
 
Basis Swaps
 
Northeast
 
(23
)
 
$
0.09

Natural Gas
 
2014
 
Basis Swaps
 
MidCon
 
(39
)
 
$
(0.18
)
Natural Gas
 
2014
 
Basis Swaps
 
Rockies
 
(78
)
 
$
(0.18
)
Natural Gas
 
2014
 
Basis Swaps
 
West
 
(27
)
 
$
0.08

NGL - Ethane
 
2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(986
)
 
$
0.28

NGL - Natural Gasoline
 
2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(822
)
 
$
2.05

Crude Oil
 
2015
 
Swaptions
 
WTI
 
(1,750
)
 
$
98.54

Natural Gas
 
2015
 
Fixed Price Swaps
 
Henry Hub
 
(35