WPX ENERGY, INC., 10-K filed on 2/28/2013
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2012
Feb. 26, 2013
Jun. 30, 2012
Document Information [Line Items]
 
 
 
Document Type
10-K 
 
 
Amendment Flag
false 
 
 
Document Period End Date
Dec. 31, 2012 
 
 
Document Fiscal Year Focus
2012 
 
 
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
 
200,132,338 
 
Entity Public Float
 
 
$ 3,204,886,378 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Current assets:
 
 
Cash and cash equivalents
$ 153 
$ 526 
Accounts receivable, net of allowance of $11 and $13 as of December 31, 2012 and 2011, respectively
443 
509 
Deferred income taxes
17 
 
Derivative assets
58 
506 
Inventories
66 
73 
Other
35 
60 
Total current assets
772 
1,674 
Investments
145 
125 
Properties and equipment, net (successful efforts method of accounting)
8,416 
8,222 
Derivative assets
10 
Other noncurrent assets
121 
401 
Total assets
9,456 
10,432 
Current liabilities:
 
 
Accounts payable
509 
702 
Accrued and other current liabilities
203 
186 
Deferred income taxes
 
116 
Derivative liabilities
14 
152 
Total current liabilities
726 
1,156 
Deferred income taxes
1,401 
1,556 
Long-term debt
1,508 1
1,503 
Derivative liabilities
Asset retirement obligations
316 
283 
Other noncurrent liabilities
133 
168 
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; 199.3 million shares issued at December 31, 2012 and 197.1 million shares issued at December 31, 2011)
Additional paid-in-capital
5,487 
5,457 
Accumulated deficit
(223)
 
Accumulated other comprehensive income
219 
Total stockholders' equity
5,268 
5,678 
Noncontrolling interests in consolidated subsidiaries
103 
81 
Total equity
5,371 
5,759 
Total liabilities and equity
$ 9,456 
$ 10,432 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Allowance for doubtful accounts
$ 11 
$ 13 
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
199,300,000 
197,100,000 
Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Product revenues:
 
 
 
Natural gas sales
$ 1,364 
$ 1,694 
$ 1,715 
Oil and condensate sales
491 
312 
126 
Natural gas liquid sales
299 
408 
285 
Total product revenues
2,154 
2,414 
2,126 
Gas management
949 
1,428 
1,742 
Net gain (loss) on derivatives not designated as hedges (Note 16)
78 
29 
27 
Other
11 
40 
Total revenues
3,189 
3,882 
3,935 
Costs and expenses:
 
 
 
Lease and facility operating
283 
262 
263 
Gathering, processing and transportation
506 
487 
320 
Taxes other than income
111 
134 
120 
Gas management, including charges for unutilized pipeline capacity
996 
1,471 
1,767 
Exploration
83 
126 
57 
Depreciation, depletion and amortization
966 
902 
811 
Impairment of producing properties and costs of acquired unproved reserves (Note 6)
225 1 2
367 1 3
175 1 4
Goodwill impairment
 
 
1,003 5
General and administrative
287 
275 
242 
Other-net
12 
 
(18)
Total costs and expenses
3,469 
4,024 
4,740 
Operating income (loss)
(280)
(142)
(805)
Interest expense
(102)
(117)
(124)
Interest capitalized
15 
Investment income and other
30 
26 
21 
Income (loss) from continuing operations before income taxes
(344)
(224)
(893)
Provision (benefit) for income taxes
(111)
(74)
44 
Income (loss) from continuing operations
(233)
(150)
(937)
Income (loss) from discontinued operations
22 
(142)
(346)
Net income (loss)
(211)
(292)
(1,283)
Less: Net income attributable to noncontrolling interests
12 
10 
Net income (loss) attributable to WPX Energy
$ (223)
$ (302)
$ (1,291)
Basic and diluted earnings (loss) per common share (Note 5):
 
 
 
Income (loss) from continuing operations
$ (1.23)
$ (0.81)
$ (4.80)
Income (loss) from discontinued operations
$ 0.11 
$ (0.72)
$ (1.75)
Net income (loss)
$ (1.12)
$ (1.53)
$ (6.55)
Weighted-average shares
198.8 
197.1 
197.1 
[2] Due to significant declines in forward natural gas and natural gas liquids prices during 2012, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future discounted cash flows. Significant judgments and assumptions in these assessments include estimates of 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. As a result, we recorded the following impairment charges. 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 Powder River and Piceance, 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 Green River. 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.
[3] Due to significant declines in forward natural gas prices, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future cash flows including potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. The annual assessment identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recorded the following impairment charges. 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 Powder River. 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 Powder River. 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.
[4] As of September 30, 2010, we had a trigger event as a result of recent significant declines in forward natural gas prices and therefore, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments are similar to those used in the goodwill evaluation and include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. The assessment performed at September 30, 2010, identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recorded a $175 million impairment charge in third-quarter 2010 related to acquired unproved reserves in the Piceance Highlands acquired in 2008. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent. Fair value measured for these properties was estimated to be approximately $9 million at September 30, 2010.
[5] Due to a significant decline in forward natural gas prices across all future production periods during 2010, we determined that we had a trigger event and thus performed an interim impairment assessment of the approximate $1 billion of goodwill related to our domestic natural gas production operations (the reporting unit). Forward natural gas prices through 2025 as of September 30, 2010, used in our analysis declined more than 22 percent on average compared to the forward prices as of December 31, 2009. We estimated the fair value of the reporting unit on a stand-alone basis by valuing proved and unproved reserves, as well as estimating the fair values of other assets and liabilities which are identified to the reporting unit. We used an income approach (discounted cash flow) for valuing reserves. The significant inputs into the valuation of proved and unproved reserves included reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, income taxes, and appropriate discount rates. To estimate the fair value of the reporting unit and the implied fair value of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure where a buyer would obtain a step-up in the tax basis of the net assets acquired. Significant assumptions in valuing proved reserves included reserves quantities of more than 4.4 trillion cubic feet of gas equivalent; forward prices averaging approximately $4.65 per thousand cubic feet of gas equivalent ("Mcfe") for natural gas (adjusted for locational differences), natural gas liquids and oil; and an after-tax discount rate of 11 percent. Unproved reserves (probable and possible) were valued using similar assumptions adjusted further for the uncertainty associated with these reserves by using after-tax discount rates of 13 percent and 15 percent, respectively, commensurate with our estimate of the risk of those reserves. In our assessment as of September 30, 2010, the carrying value of the reporting unit, including goodwill, exceeded its estimated fair value. We then determined that the implied fair value of the goodwill was zero. As a result of our analysis, we recognized a full $1 billion impairment charge related to this goodwill.
Consolidated Statements of Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Net income (loss) attributable to WPX Energy
$ (223)
$ (302)
$ (1,291)
Other comprehensive income (loss):
 
 
 
Change in fair value of cash flow hedges, net of tax
57 1
262 1
321 1
Net reclassifications into earnings of net cash flow hedge gains, net of tax
(274)2
(211)2
(225)2
Other comprehensive income (loss), net of tax
(217)
51 
96 
Comprehensive income (loss) attributable to WPX Energy
$ (440)
$ (251)
$ (1,195)
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income tax for net cash flow hedges
$ 33 
$ 151 
$ 184 
Income tax provision for cash flow hedge gains
$ 159 
$ 120 
$ 129 
Consolidated Statements of Changes in Equity (USD $)
In Millions, unless otherwise specified
Total
Common Stock
Capital in Excess of Par Value
Accumulated Other Comprehensive Income (Loss)
Total Stockholders' Equity
Noncontrolling Interests in Consolidated Subsidiaries
Accumulated Deficit
Williams Net Investment
Beginning balance at Dec. 31, 2009
$ 5,390 
 
 
$ 72 
$ 5,326 
$ 64 1
 
$ 5,254 
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss)
(1,283)
 
 
 
(1,291)
1
 
(1,291)
Other comprehensive income (loss)
96 
 
 
96 
96 
 
 
 
Comprehensive income (loss)
(1,187)
 
 
 
 
 
 
 
Cash proceeds in excess of historical book value related to assets sold to a Williams' affiliate
244 
 
 
 
244 
 
 
244 
Net transfers with Williams
37 
 
 
 
37 
 
 
37 
Ending balance at Dec. 31, 2010
4,484 
 
 
168 
4,412 
72 1
 
4,244 
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss)
(292)
 
 
 
(302)
10 1
 
(302)
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
 
 
 
 
 
Ending balance at Dec. 31, 2011
5,759 
5,457 
219 
5,678 
81 1
 
 
Comprehensive income:
 
 
 
 
 
 
 
 
Net income (loss)
(211)
 
 
 
(223)
12 1
(223)
 
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 
 
 
 
Ending balance at Dec. 31, 2012
$ 5,371 
$ 2 
$ 5,487 
$ 2 
$ 5,268 
$ 103 1
$ (223)
 
Consolidated Statements of Changes in Equity (Parenthetical)
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
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, 2012
Dec. 31, 2011
Dec. 31, 2010
Operating Activities
 
 
 
Net income (loss)
$ (211)
$ (292)
$ (1,283)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
973 
951 
882 
Deferred income tax benefit
(160)
(176)
(166)
Provision for impairment of goodwill and properties and equipment (including certain exploration expenses)
288 
694 
1,734 
Amortization of stock-based awards
28 
 
(Gain) loss on sales of other assets
(42)
(1)
(22)
Cash provided (used) by operating assets and liabilities:
 
 
 
Accounts receivable
68 
(100)
28 
Inventories
(16)
Margin deposits and customer margin deposit payable
(5)
(18)
(1)
Other current assets
(11)
19 
Accounts payable
(128)
131 
(54)
Accrued and other current liabilities
12 
10 
(62)
Changes in current and noncurrent derivative assets and liabilities
(32)
(45)
Other, including changes in other noncurrent assets and liabilities
(11)
42 
Net cash provided by operating activities
794 
1,206 
1,056 
Investing Activities
 
 
 
Capital expenditures
(1,521)1
(1,572)1
(1,856)1
Purchase of business
 
 
(949)
Proceeds from sales of assets
310 
15 
493 
Purchases of investments
(2)
(12)
(7)
Other
13 
(18)
Net cash used in investing activities
(1,204)
(1,556)
(2,337)
Financing Activities
 
 
 
Proceeds from common stock
 
 
Proceeds from long term debt
1,502 
 
Proceeds from revolver debt
50 
 
 
Payments of revolver debt
(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 
1,045 
Net changes in Williams' net investment, including a $981 distribution in 2011
 
(777)
241 
Other
(15)
(2)
Net cash provided by financing activities
37 
839 
1,284 
Net increase (decrease) in cash and cash equivalents
(373)
489 
Cash and cash equivalents at beginning of period
526 
37 
34 
Cash and cash equivalents at end of period
$ 153 
$ 526 
$ 37 
Consolidated Statements of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Net changes in Williams' net investment, distribution
 
$ 981 
 
Increase to properties and equipment
(1,449)
(1,641)
(1,891)
Changes in related accounts payable
(72)
69 
35 
Capital expenditures
$ (1,521)1
$ (1,572)1
$ (1,856)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

Note 1. 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.

Domestic includes natural gas, oil, and NGL development and production and gas management activities located in Colorado, New Mexico, North Dakota (Bakken Shale), Pennsylvania (Marcellus Shale), 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, San Juan, Powder River, Williston (Bakken Shale), Green River, and Appalachian (Marcellus Shale) Basins. Associated with our commodity production are sales and marketing 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 concessions in Argentina and Colombia.

The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company”, comprised substantially all of the exploration and production reportable segment of The Williams Companies, Inc. prior to 2012. In these notes, WPX Energy, Inc. is at times referred to in the first person as “WPX”, “we”, “us” or “our”. The Williams Companies, Inc. and its affiliates, including Williams Partners L.P. (“Williams Partners”) are at times referred to collectively as “Williams”.

On February 16, 2011, Williams announced that its Board of Directors had approved pursuing a plan to separate Williams’ businesses into two stand-alone, publicly traded companies. As a result, WPX Energy, Inc. was formed to effect the separation. In July 2011, Williams contributed to the Company its investment in certain subsidiaries related to its domestic exploration and production business, including its wholly-owned subsidiaries WPX Energy Holdings, LLC (formerly Williams Production Holdings, LLC) and WPX Energy Production, LLC (formerly Williams Production Company, LLC), as well as all ongoing operations of WPX Energy Marketing, LLC (formerly Williams Gas Marketing, Inc.). Additionally, Williams contributed and transferred to the Company its investment in certain subsidiaries related to its international exploration and production business, including its 69 percent ownership interest in Apco in October 2011. We refer to the collective contributions described herein as the “Contribution”.

On November 30, 2011, the Board of Directors of Williams approved the spin-off of the Company. The spin-off was completed by way of a pro rata distribution on December 31, 2011 of WPX common stock to Williams’ stockholders of record as of the close of business on December 14, 2011, the spin-off record date. Each Williams’ stockholder received one share of WPX common stock for every three shares of Williams common stock held by such stockholder on the record date. See Note 3 for further discussion of agreements entered at the time of the spin-off, including a separation and distribution agreement, a transition services agreement, an employee matters agreement and a tax sharing agreement, among others.

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. However, the financial statements 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 and 2010. 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 and 2010 with Williams’ other operating businesses, which generally settled monthly, are shown as accounts receivable or accounts payable for December 31, 2011 (see Note 3). 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 Barnett Shale and Arkoma operations as discontinued operations for all periods presented.

Additionally, the accompanying consolidated financial statements and notes include the results of operations of Williams’ former power business (most of which was disposed in 2007) as discontinued operations. See Note 11 for a discussion of contingencies related to this discontinued power business.

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 and goodwill;

 

   

Valuations of derivatives;

 

   

Hedge accounting correlations and probability;

 

   

Estimation of oil and natural gas reserves; and

 

   

Assessments of litigation-related contingencies.

 

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 primarily consists of approximately $19 million in both 2012 and 2011 related to escrow accounts established as part of the settlement agreement with certain California utilities and is included in other 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, our international segment holds approximately $9 million of restricted cash in 2012 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 $42 million in 2012 and $39 million in 2011. Additionally, we have natural gas in storage of $24 million in 2012 and $34 million in 2011 primarily related to our gas management activities. 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 $11 million in 2012, $10 million in 2011 and $2 million in 2010.

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 or 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 other—net included in operating income (loss).

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 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.

Goodwill

As a result of significant declines in forward natural gas prices during 2010, we performed an interim impairment assessment of our goodwill related to our domestic production reporting unit. As a result of that assessment, we recorded an impairment of goodwill of approximately $1 billion and no longer have any goodwill recorded on the Consolidated Balance Sheets related to our domestic operations (see Note 15).

Judgments and assumptions are inherent in our management’s estimate of future cash flows used to determine the estimate of the reporting unit’s fair value.

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 for 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, natural gas liquids, and oil and condensate 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, 2012 and 2011 was insignificant. Additionally, natural gas revenues include $423 million in 2012, $326 million in 2011 and $333 million in 2010 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 April 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 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 $46 million in 2012, $35 million in 2011 and $44 million in 2010.

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

Beginning with the 2012 tax year, we will file initial 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 and 2010 were calculated on a separate return basis for us and our subsidiaries, except for certain adjustments, such as alternative minimum tax calculated at the consolidated level by Williams, for which the ultimate expected benefit to us could not be determined until the date of deconsolidation. 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 can be subject to accelerated vesting if certain future stock prices or specific financial performance targets are achieved. Stock options 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, unless otherwise noted. The impact of our December 31, 2011 stock issuance has been given effect to all periods prior to 2011 (see Note 5).

Discontinued Operations
Discontinued Operations

Note 2. 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. The Barnett Shale properties included approximately 27,000 net acres, interests in 320 wells and 91 miles of pipeline. The Arkoma properties included approximately 66,000 net acres, interests in 525 wells and 115 miles of pipeline.

Summarized Results of Discontinued Operations

 

     2012     2011     2010  
     (Millions)  

Revenues

   $ 28     $ 118      $ 115   
  

 

 

   

 

 

   

 

 

 

Income (loss) from discontinued operations before impairments, gain on sale and income taxes

   $ (3 )   $ (15   $ (41

Gain on sale

     38        —         —    

Impairments

     —         (209     (503

Less: Provision (benefit) for income taxes

     13        (82     (198
  

 

 

   

 

 

   

 

 

 

Income (loss) from discontinued operations

   $ 22     $ (142   $ (346
  

 

 

   

 

 

   

 

 

 

The impairments in 2011 and 2010 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 and $503 million in 2011 and 2010, respectively. 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

Note 3. 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 from Williams. 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. At December 31, 2011, certain paid time off accruals approximating $13 million were transferred from Williams to us and have been reflected in accrued liabilities.

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. For the years of 2011 and 2010, the following were considered related party transactions. Beginning January 1, 2013, Williams and its subsidiaries were no longer related parties, therefore only amounts related to 2011 and 2010 are disclosed as related parties. 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.

During fourth-quarter 2010, the Company sold certain gathering and processing assets in Colorado’s Piceance Basin (the “Piceance Sale”) with a net book value of $458 million to Williams Partners, an entity under the common control of Williams, in exchange for $702 million in cash and 1.8 million Williams Partners limited partner units. As the Company and Williams Partners were under common control at that time, no gain was recognized on this transaction in the Consolidated Statements of Operations. Accordingly, the $244 million difference between the cash consideration received and the historical net book value of the assets has been reflected in the Consolidated Statements of Equity for the year ended December 31, 2010. Since the Williams Partners units received in this transaction by the Company were intended to be (and were, as described below) distributed through a dividend to Williams, these units (as well as the tax effects associated with these units of $42 million) have been presented net within equity and are included in net transfers with Williams in 2010. Further, as a result of the limitations on the Company’s ability to sell these units and the subsequent dividend to Williams, no gains on the value of the common units during the holding period were recognized in the Consolidated Statements of Operations. In conjunction with the Piceance Sale, we entered into long-term contracts with Williams Partners for gathering and processing of our natural gas production in the area. Due to the continuation of significant direct cash flows related to these assets, historical operating results of these assets have been presented in the Consolidated Statements of Operations as continuing operations for periods prior to the sale. In March 2011, the 1.8 million Williams Partners units and related tax basis were distributed via dividend to Williams.

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 and $10 million for the years ended December 31, 2011 and 2010, respectively, 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 and December 31, 2010, respectively.

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 and 2010 of the transactions with Williams or its affiliates (including amounts in discontinued operations) discussed above:

 

     2011      2010  
     (Millions)  

Product revenues—sales of NGLs to Williams Partners

   $ 258       $ 277   

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

     586         509   

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

     21         23   

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

     

Gathering and processing

     298         163   

Transportation

     44         25   

General and administrative from Williams:

     

Direct employee salary and benefit costs

     111         102   

Charges for general and administrative services

     62         58   

Allocated general corporate costs

     62         64   

Other

     16         12   

Interest expense on notes payable to Williams

     96         119   

In addition, the current amount due to or from affiliates at December 31, 2011 consisted of trade receivables and payables resulting from the sale of products to and cost of gathering services provided by Williams Partners. Below is a summary of these payables and receivables and other assets and liabilities with Williams and its affiliates at December 31, 2011:

 

     December 31, 2011  
     (Millions)  

Current:

  

Accounts receivable:

  

Due from Williams Partners and another Williams subsidiary

   $ 62   
  

 

 

 

Other noncurrent assets—Due from Williams

   $ 11   
  

 

 

 

Accounts payable:

  

Due to Williams Partners

   $ 35   

Due to Williams for accrued payroll and benefits

     10   

Due to Williams for administrative expenses

     14   
  

 

 

 
   $ 59   
  

 

 

 

Noncurrent liability to Williams

   $ 48   
  

 

 

 
Investment Income and Other
Investment Income and Other

Note 4. Investment Income and Other

Investment income

 

     Years Ended December 31,  
     2012      2011      2010  
     (Millions)  

Equity earnings

   $ 30      $ 24       $ 20   

Other

     —          2         1   
  

 

 

    

 

 

    

 

 

 

Total investment income and other

   $ 30      $ 26       $ 21   
  

 

 

    

 

 

    

 

 

 

Investments

 

     December 31,  
     2012      2011  
     (Millions)  

Petrolera Entre Lomas S.A.—40.8%

   $ 109      $ 90   

Other

     36        35   
  

 

 

    

 

 

 
   $ 145      $ 125   
  

 

 

    

 

 

 

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 $12 million in 2012, $17 million in 2011 and $19 million in 2010.

Summarized Financial Position and Results of Operations of Equity Method Investments (Unaudited)

 

     December 31,  
     2012      2011  
     (Millions)  

Current assets

   $ 100       $ 81   

Noncurrent assets

     512         491   

Current liabilities

     133         75   

Noncurrent liabilities

     31         106   

 

     Years Ended December 31,  
       2012          2011          2010    
     (Millions)  

Gross revenue

   $ 383       $ 323       $ 227   

Operating income

     150         122         110   

Net income

     107         90         79   
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations

Note 5. Earnings (Loss) Per Common Share from Continuing Operations

 

     Years Ended December 31,  
     2012     2011     2010  
     (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

   $ (245 )   $ (160   $ (945
  

 

 

   

 

 

   

 

 

 

Basic weighted-average shares

     198.8       197.1        197.1   
  

 

 

   

 

 

   

 

 

 

Diluted weighted-average shares

     198.8       197.1        197.1   
  

 

 

   

 

 

   

 

 

 

Earnings (loss) per common share from continuing operations:

      

Basic

   $ (1.23 )   $ (0.81   $ (4.80
  

 

 

   

 

 

   

 

 

 

Diluted

   $ (1.23 )   $ (0.81   $ (4.80
  

 

 

   

 

 

   

 

 

 

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 each period presented for 2011 and 2010 in the calculation of basic and diluted weighted average shares.

For 2012 and 2011, approximately 1.9 million and 2.9 million, respectively, weighted-average nonvested restricted stock units and 1.0 million and 1.2 million, respectively, weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.

The table below includes information related to stock options that were outstanding at December 31, 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.

 

     2012  

Options excluded (millions)

     1.3  

Weighted-average exercise price of options excluded

     $18.17   

Exercise price range of options excluded

   $ 16.46 – $20.97   

Fourth quarter weighted-average market price(a)

     $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, Exploration Expenses and Other Accruals
Asset Sales, Impairments, Exploration Expenses and Other Accruals

Note 6. Asset Sales, Impairments, Exploration Expenses and Other Accruals

The following table presents a summary of significant gains or losses reflected in impairment of producing properties and costs of acquired unproved reserves, goodwill impairment, and other—net within costs and expenses. These significant adjustments are primarily associated with our domestic operations.

 

     Years Ended December 31,  
     2012      2011      2010  
     (Millions)  

Goodwill impairment

   $ —        $ —         $ 1,003  

Impairment of producing properties and costs of acquired unproved reserves(a)

   $ 225       $ 367       $ 175   

Gain on sales of other assets

   $ 4       $ 1       $ 22   

 

(a) Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.

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.

As a result of significant declines in forward natural gas prices during 2010, we performed an impairment assessment of our capitalized costs related to goodwill and domestic producing properties. As a result of these assessments, we recorded an impairment of goodwill, as noted above, and an impairment of our capitalized costs of certain acquired unproved reserves in the Piceance Highlands acquired in 2008 of $175 million (see Note 15).

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.

In July 2010, we sold a portion of gathering and processing facilities in the Piceance Basin to a third party for cash proceeds of $30 million resulting in a gain of $12 million. The remaining portion of the facilities was part of the Piceance Sale (see Note 3). Also in 2010, we exchanged undeveloped leasehold acreage in different areas with a third party resulting in a $7 million gain.

 

Exploration Expense

The following presents a summary of exploration expense:

 

    Years Ended December 31,  
      2012         2011         2010    
    (Millions)  

Geologic and geophysical costs

  $ 21      $ 18      $ 21   

Dry hole costs

    4        13        17   

Unproved leasehold property impairment, amortization and expiration

    58        95        19   
 

 

 

   

 

 

   

 

 

 

Total exploration expense

  $ 83      $ 126      $ 57   
 

 

 

   

 

 

   

 

 

 

Dry hole costs in 2011 reflect an $11 million dry hole expense in connection with a Marcellus Shale well in Columbia County, Pennsylvania, while 2010 reflects dry hole expense associated primarily with wells in the Paradox Basin.

Unproved leasehold impairment, amortization and expiration in 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.

Properties and Equipment
Properties and Equipment

Note 7. Properties and Equipment

Properties and equipment is carried at cost and consists of the following:

 

     Estimated
Useful
Life(a)
(Years)
  

 

December 31,

 
        2012     2011  
          (Millions)  

Proved properties

   (b)    $ 11,267      $ 9,806   

Unproved properties

   (c)      1,156        1,528   

Gathering, processing and other facilities

   15-25      247        89   

Construction in progress

   (c)      497        677   

Other

   3-40      172        99   
     

 

 

   

 

 

 

Total properties and equipment, at cost

        13,339        12,199   

Accumulated depreciation, depletion and amortization

        (4,923     (3,977
     

 

 

   

 

 

 

Properties and equipment—net

      $ 8,416      $ 8,222   
     

 

 

   

 

 

 

 

(a) Estimated useful lives are presented as of December 31, 2012.
(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 (Marcellus Shale) and the Williston Basin (Bakken Shale) and costs of acquired unproved reserves in the Powder River and Piceance Basins.

Construction in progress includes $65 million in 2012 and $113 million in 2011 related to wells located in Powder River. In order to produce gas from the coal seams, an extended period of dewatering is required prior to natural gas production.

 

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 2012 and 2011 is presented below.

 

     2012     2011  
     (Millions)  

Balance, January 1

   $ 289     $ 274   

Liabilities incurred during the period

     19       20   

Liabilities settled during the period

     (7 )     (2

Estimate revisions

     (1 )     (23

Accretion expense(a)

     21       20   
  

 

 

   

 

 

 

Balance, December 31

   $ 321     $ 289   
  

 

 

   

 

 

 

Amount reflected as current

   $ 5     $ 6   
  

 

 

   

 

 

 

 

(a) Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.

Estimate revisions in 2011 are primarily associated with changes in anticipated well lives and plug and abandonment costs.

Accounts Payable and Accrued and Other Current Liabilities
Accounts Payable and Accrued and Other Current Liabilities

Note 8. Accounts Payable and Accrued and Other Current Liabilities

Accounts Payable

 

     December 31,  
     2012      2011  
     (Millions)  

Trade

   $ 209       $ 331   

Accrual for capital expenditures

     126         207   

Royalties

     106         111   

Cash overdrafts

     34         28   

Other

     34        25   
  

 

 

    

 

 

 
   $ 509       $ 702   
  

 

 

    

 

 

 

Accrued and other current liabilities

 

     December 31,  
     2012      2011  
     (Millions)  

Taxes other than income taxes

   $ 54       $ 79   

Accrued interest

     42        13   

Compensation and benefit related accruals

     52         13   

Other, including other loss contingencies

     55         81   
  

 

 

    

 

 

 
   $ 203       $ 186
Debt and Banking Arrangements
Debt and Banking Arrangements

Note 9. Debt and Banking Arrangements

As of the indicated dates, our debt consisted of the following:

 

     December 31,  
     2012(a)      2011  
     (Millions)  

5.250% Senior Notes due 2017

   $ 400      $ 400   

6.000% Senior Notes due 2022

     1,100        1,100   

Other

     —          1   

Apco

     8        2   
  

 

 

    

 

 

 
   $ 1,508      $ 1,503   
  

 

 

    

 

 

 

 

(a) Interest paid on debt for 2012 totaled $58 million.

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. The Credit Facility Agreement became effective November 1, 2011. At December 31, 2012 there were no amounts outstanding 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, 2012. 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, 2012 a total of $312 million in letters of credit have been issued.

Apco

Apco has a loan agreement with a financial institution for a $10 million bank line of credit. The funds could be borrowed during a one-year period which ended in March 2012. As of December 31, 2012, Apco has 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

Note 10. Provision (Benefit) for Income Taxes

The provision (benefit) for income taxes from continuing operations includes:

 

     Years Ended December 31,  
     2012     2011     2010  
     (Millions)  

Provision (benefit):

      

Current:

      

Federal

   $ 48     $ 49      $ 72   

State

     3        7        5   

Foreign

     14       10        11   
  

 

 

   

 

 

   

 

 

 
     65       66        88   
  

 

 

   

 

 

   

 

 

 

Deferred:

      

Federal

     (162 )     (139     (41

State

     (13 )     (1     (3

Foreign

     (1 )     —          —     
  

 

 

   

 

 

   

 

 

 
     (176 )     (140     (44
  

 

 

   

 

 

   

 

 

 

Total provision (benefit)

   $ (111 )   $ (74   $ 44   
  

 

 

   

 

 

   

 

 

 

 

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,  
     2012     2011     2010  
     (Millions)  

Provision (benefit) at statutory rate

   $ (120 )   $ (79   $ (313

Increases (decreases) in taxes resulting from:

      

State income taxes (net of federal benefit)

     (7     (5     2   

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

     —         9       —    

Alternative minimum tax credits

     11       —         —     

Foreign operations—net

     4       —         4   

Goodwill impairment

     —         —         351   

Other—net

     1       1       —    
  

 

 

   

 

 

   

 

 

 

Provision (benefit) for income taxes

   $ (111 )   $ (74   $ 44   
  

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes includes $52 million, $40 million and $36 million of foreign income in 2012, 2011 and 2010, respectively.

Significant components of deferred tax liabilities and deferred tax assets are as follows:

 

     December 31,  
     2012      2011  
     (Millions)  

Deferred tax liabilities:

     

Properties and equipment

   $ 1,652      $ 1,779   

Other, net

     19        137   
  

 

 

    

 

 

 

Total deferred tax liabilities

     1,671        1,916   
  

 

 

    

 

 

 

Deferred tax assets:

     

Accrued liabilities and other

     176        146   

Alternative minimum tax credits

     99        98   

Loss carryovers

     31        16   
  

 

 

    

 

 

 

Total deferred tax assets

     306        260   

Less: valuation allowance

     19        16   
  

 

 

    

 

 

 

Total net deferred tax assets

     287        244   
  

 

 

    

 

 

 

Net deferred tax liabilities

   $ 1,384      $ 1,672   
  

 

 

    

 

 

 

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 provision for 2011 and 2010 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, for which the ultimate expected impact to the Company could not be determined until the date of deconsolidation. 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, with respect to the payment of taxes, filing of tax returns, reimbursements of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off and other matters regarding taxes.

 

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 reflected within provision (benefit) for income taxes in 2012. Additionally, the Company expects to have alternative minimum tax liability for 2012.

As of December 31, 2012, the Company has approximately $500 million of state net operating loss carryovers of which approximately 99 percent expire after 2022. The Company assesses available positive and negative evidence to estimate if sufficient future taxable income will be generated in a particular state to utilize the net operating loss carryover for that state. Based on that assessment, a valuation allowance was recorded at December 31, 2012 and 2011 to reduce the recognized tax assets associated with state losses, net of federal benefit, to an amount that will more likely than not be realized by the Company.

Undistributed earnings of certain consolidated foreign subsidiaries excluding amounts related to foreign equity investments at December 31, 2012, totaled approximately $77 million. No provision for deferred U.S. income taxes has been made for these subsidiaries, except with respect to foreign equity investments, because the Company intends to permanently reinvest such earnings in foreign operations.

Cash payments for domestic income taxes (net of receipts) were $40 million, $10 million and $5 million in 2012, 2011 and 2010, respectively. Additionally, payments made directly to international taxing authorities were $11 million, $10 million and $8 million in 2012, 2011 and 2010, respectively. The payments and receipts for domestic income taxes for 2011 and 2010 (prior to the spin-off) were made to or received from Williams in accordance with Williams’ intercompany tax allocation procedure.

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.

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. The statute of limitations for most states expires one year after expiration of the IRS statute. Income tax returns for our foreign operations, primarily in Argentina, are open to audit for the 2005 to 2012 tax years.

As of December 31, 2012, 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

Note 11. 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 is 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. We anticipate litigating the second reserved claim in 2013. We believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law. At this time, the plaintiffs have not provided us a sufficient framework to calculate an estimated range of exposure related to their claims.

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 alleges failure to pay royalty on hydrocarbons including drip condensate, fraud and misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons, violation of the New Mexico Oil and Gas Proceeds Payment Act, bad faith breach of contract and unjust enrichment. 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 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. 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 October 2005 through December 2012, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $116 million.

 

The New Mexico State Land Office Commissioner has filed suit against us in Santa Fe County alleging that we have underpaid royalties due per the oil and gas leases with the State of New Mexico. In August 2011, the parties agreed to stay this matter pending the New Mexico Supreme Court’s resolution of a similar matter involving a different producer. At this time, we do not have a sufficient basis to calculate an estimated range of exposure related to this claim.

Environmental matters

The EPA 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, one hour nitrogen dioxide emission limits, 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 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 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 have appealed to the United States Court of Appeals for the Ninth Circuit. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential 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, 2012, 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, 2012 and December 31, 2011, the Company had accrued approximately $18 million and $23 million, respectively, for loss contingencies associated with royalty litigation, reporting of natural gas information to trade publications and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.

 

Commitments

As part of managing our commodity price risk, we utilize contracted pipeline capacity to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2012 are as follows:

 

     (Millions)  

2013

   $ 205   

2014

     211   

2015

     207   

2016

     192   

2017

     175   

Thereafter

     741   
  

 

 

 

Total

   $ 1,731   
  

 

 

 

We also have certain commitments to an equity investee and others, primarily for natural gas gathering and treating services and well completion services, which total $634 million over approximately seven 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 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 Basin) 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, 2012, are payable as follows:

 

     (Millions)  

2013

   $ 63   

2014

     59   

2015

     41   

2016

     10   

2017

     8   

Thereafter

     29   
  

 

 

 

Total

   $ 210   
  

 

 

 

Total rent expense, excluding amounts capitalized, was $20 million, $12 million and $12 million in 2012, 2011 and 2010, 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

Note 12. 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. Contributions to this plan were $6 million in 2012 and approximately $10 million was included in accrued and other current liabilities at December 31, 2012 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 support our operations are 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 provides pension benefits for its eligible employees. Pension expense charged to us by Williams for 2011 and 2010 totaled $8 million and $7 million, respectively.

Other postretirement benefits

Williams is the sponsor of subsidized retiree medical and life insurance benefit plans (“other postretirement benefits”) that provides 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 and 2010 totaled less than $1 million for each period.

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 and $5 million in 2011 and 2010, respectively, for Williams’ matching contributions to this plan.

Stock-Based Compensation
Stock-Based Compensation

Note 13. 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 110 thousand shares at an average price of $13.08 per share during 2012.

The Williams Companies, Inc. 2011 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. Additionally, certain of our eligible direct employees participated in Williams’ ESPP. The ESPP enables eligible participants to purchase through payroll deductions a limited amount of Williams’ common stock at a discounted price.

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 provide 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 years prior to 2012. 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, 2012, 2011 and 2010 was $28 million, $18 million, and $14 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2012 was $43 million. This amount is comprised of $2 million related to stock options and $41 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 2.4 years.

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2012.

 

      WPX Plan  

Stock Options

   Options     Weighted-
Average
Exercise
Price
     Aggregate
Intrinsic
Value
 
     (Millions)            (Millions)  

Outstanding at December 31, 2011

     4.2     $ 11.41      $ 29  
       

 

 

 

Granted

     0.3     $ 18.16     

Exercised

     (0.4 )   $ 4.67     

Expired

     —       $ —       
  

 

 

      

Outstanding at December 31, 2012(a)

     4.1     $ 12.68      $ 14  
  

 

 

   

 

 

    

 

 

 

Exercisable at December 31, 2012

     3.2      $ 11.74      $ 13  
  

 

 

   

 

 

    

 

 

 

 

(a) Includes approximately 598 thousand shares held by Williams’ employees at a weighted average price of $8.48 per share.

The total intrinsic value of options exercised during the years ended December 31, 2012, 2011 and 2010 was $5 million, $7 million, and $2 million, respectively.

 

The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2012.

 

     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 $6.76

     1.0       $ 5.87         4.7         1.0       $ 5.87         4.7   

$ 9.08 to $11.75

     1.1       $ 11.28         5.0         0.9       $ 11.17         4.5   

$12.00 to $15.67

     0.7       $ 14.41         3.8         0.7       $ 14.41         3.8   

$16.46 to $20.97

     1.3       $ 18.17         7.4         0.6       $ 19.13         6.0   
  

 

 

          

 

 

       

Total

     4.1       $ 12.68         5.5         3.2       $ 11.74         4.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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  
     2012     2011  

Weighted-average or grant date fair value of options granted

   $ 7.79     $ —    
  

 

 

   

 

 

 

Weighted-average conversion date fair value options granted

     $ 8.48   
    

 

 

 

Weighted-average assumptions:

    

Dividend yield

     —       —  

Volatility

     43.8     45

Risk-free interest rate

     1.17     0.377

Expected life (years)

     6.0        2.8   

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 rate 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 $2 million during 2012.

 

Nonvested Restricted Stock Units

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2012.

 

     WPX Plan  

Restricted Stock Units

   Shares     Weighted-
Average
Fair Value(a)
 
     (Millions)        

Nonvested at December 31, 2011

     4.6     $ 9.69  

Granted

     2.8     $ 17.35  

Forfeited

     (0.2 )   $ 16.20  

Cancelled

     —       $ —    

Vested

     (2.4   $ 5.71   
  

 

 

   

Nonvested at December 31, 2012

     4.8     $ 16.45  
  

 

 

   

 

 

 

 

(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  
     2012      2011      2010  

Weighted-average grant date fair value of restricted stock units granted during the year, per share

   $ 17.35       $ 27.74       $ 20.00   
  

 

 

    

 

 

    

 

 

 

Total fair value of restricted stock units vested during the year ($’s in millions)

   $ 14       $ 10       $ 9   
  

 

 

    

 

 

    

 

 

 

Performance-based shares granted represent 13 percent of nonvested restricted stock units outstanding at December 31, 2012. 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

Note 14. 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 as of December 31, 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

Note 15. 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 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 and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

 

     December 31, 2012      December 31, 2011  
     Level 1      Level 2      Level 3      Total      Level 1      Level 2      Level 3      Total  
            (Millions)             (Millions)  

Energy derivative assets

   $ 20      $ 38      $ 2      $ 60      $ 55       $ 454       $ 7       $ 516   

Energy derivative liabilities

   $ 11      $ 1      $ 3      $ 15      $ 41       $ 112       $ 6       $ 159   

Long-term debt(a)

   $ —        $ 1,617      $ —        $ 1,617      $ —        $ 1,523      $ —        $ 1,523  

 

(a) The carrying value of long-term debt, excluding capital leases, was $1,508 million and $1,502 million as of December 31, 2012 and 2011, 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 crude oil swaps entered into, we granted crude oil swaptions to the swap counterparties in exchange for receiving premium hedged prices on the 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 by location, 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. 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 98 percent of the net fair value of our derivatives portfolio expiring in the next 12 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, 2012, 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, 2012 or 2011. 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.

Level 3 Fair Value Measurements Using Significant Unobservable Inputs

 

     Years ended December 31,  
     2012
Net Energy
Derivatives
    2011
Net Energy
Derivatives
    2010
Net Energy
Derivatives
 
     (Millions)  

Beginning balance

   $ 1      $ 1      $ 1   

Realized and unrealized gains (losses):

      

Included in income (loss) from continuing operations

     3       15        1   

Included in other comprehensive income (loss)

     —         —         —    

Purchases, issuances, and settlements

     (5 )     (12     (1

Transfers out of Level 3

     —         (3 )     —    
  

 

 

   

 

 

   

 

 

 

Ending balance

   $ (1 )   $ 1      $ 1   
  

 

 

   

 

 

   

 

 

 

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

   $ (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.

 

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,
 
         2012             2011             2010      
     (Millions)  

Impairments:

      

Goodwill (Note 6)

   $ —       $ —       $ 1,003 (c) 

Producing properties and costs of acquired unproved reserves (Note 6)

     225 (a)      367 (b)      175 (d) 
  

 

 

   

 

 

   

 

 

 
   $ 225     $ 367      $ 1,178   
  

 

 

   

 

 

   

 

 

 

 

(a) Due to significant declines in forward natural gas and natural gas liquids prices during 2012, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future discounted cash flows. Significant judgments and assumptions in these assessments include estimates of 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. As a result, we recorded the following impairment charges. 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 Powder River and Piceance, 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 Green River. 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.

 

(b) Due to significant declines in forward natural gas prices, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future cash flows including potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. The annual assessment identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recorded the following impairment charges. 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 Powder River. 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 Powder River. 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.

 

(c) Due to a significant decline in forward natural gas prices across all future production periods during 2010, we determined that we had a trigger event and thus performed an interim impairment assessment of the approximate $1 billion of goodwill related to our domestic natural gas production operations (the reporting unit). Forward natural gas prices through 2025 as of September 30, 2010, used in our analysis declined more than 22 percent on average compared to the forward prices as of December 31, 2009. We estimated the fair value of the reporting unit on a stand-alone basis by valuing proved and unproved reserves, as well as estimating the fair values of other assets and liabilities which are identified to the reporting unit. We used an income approach (discounted cash flow) for valuing reserves. The significant inputs into the valuation of proved and unproved reserves included reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, income taxes, and appropriate discount rates. To estimate the fair value of the reporting unit and the implied fair value of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure where a buyer would obtain a step-up in the tax basis of the net assets acquired. Significant assumptions in valuing proved reserves included reserves quantities of more than 4.4 trillion cubic feet of gas equivalent; forward prices averaging approximately $4.65 per thousand cubic feet of gas equivalent (“Mcfe”) for natural gas (adjusted for locational differences), natural gas liquids and oil; and an after-tax discount rate of 11 percent. Unproved reserves (probable and possible) were valued using similar assumptions adjusted further for the uncertainty associated with these reserves by using after-tax discount rates of 13 percent and 15 percent, respectively, commensurate with our estimate of the risk of those reserves. In our assessment as of September 30, 2010, the carrying value of the reporting unit, including goodwill, exceeded its estimated fair value. We then determined that the implied fair value of the goodwill was zero. As a result of our analysis, we recognized a full $1 billion impairment charge related to this goodwill.
(d) As of September 30, 2010, we had a trigger event as a result of recent significant declines in forward natural gas prices and therefore, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments are similar to those used in the goodwill evaluation and include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. The assessment performed at September 30, 2010, identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recorded a $175 million impairment charge in third-quarter 2010 related to acquired unproved reserves in the Piceance Highlands acquired in 2008. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent. Fair value measured for these properties was estimated to be approximately $9 million at September 30, 2010.
Derivatives and Concentration of Credit Risk
Derivatives and Concentration of Credit Risk

Note 16. 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, natural gas liquids and crude oil 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 began entering into commodity derivative contracts that will continue to serve as economic hedges but will not be designated as cash flow hedges for accounting purposes as we have 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 will realize at the end of the first quarter of 2013.

We produce, buy and sell natural gas, natural gas liquids and crude oil 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, natural gas liquids and crude oil. 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 volumes that are economic hedges of production volumes as well as the table depicts the notional amounts of the net long (short) positions which do not represent economic hedges of our production, both which are included in our commodity derivatives portfolio as of December 31, 2012.

Derivatives related to production

 

Commodity

   Period   

Contract Type(a)

  

Location

   Notional Volume(b)     Weighted Average
Price(c)
 

Crude Oil

   2013    Fixed Price Swaps    WTI      (9,000   $ 100.52   

Natural Gas

   2013    Location Swaps    Northeast      (25   $ 4.63   

Natural Gas

   2013    Location Swaps    Rockies      (20   $ 3.89   

Natural Gas

   2013    Location Swaps    San Juan      (10   $ 3.93   

 

Derivatives primarily related to storage and transportation

 

Commodity

   Period   

Contract Type(d)

  

Location(e)

   Notional Volume(b)
    Weighted Average
Price(f)
 

Natural Gas

   2013    Fixed Price Swaps    Multiple      (21     —     

Natural Gas

   2013    Basis Swaps    Multiple      (27     —     

Natural Gas

   2013    Index    Multiple      (81     —     

Natural Gas

   2014    Basis Swaps    Multiple      (1     —     

Natural Gas

   2014    Index    Multiple      (20     —     

Natural Gas

   2015    Basis Swaps    Multiple      (6     —     

Natural Gas

   2015    Index    Multiple      (3     —     

Natural Gas

   2016    Index    Multiple      2        —     

Natural Gas

   2017    Index    Multiple      2        —     

 

(a) WPX Equity Production Hedges for crude oil are business day average swaps and the natural gas hedges are fixed price at location swaps.
(b) Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.
(c) The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.
(d) WPX Marketing enters into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.
(e) WPX Marketing transacts at multiple locations around our core assets to maximize the economic value of our transportation, storage and asset management agreements.
(f) The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.

Fair values and gains (losses)

The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

 

     December 31,  
     2012      2011  
     Assets      Liabilities      Assets      Liabilities  
     (Millions)  

Derivatives related to production designated as hedging instruments

   $ 5      $      $ 360       $ 13   
  

 

 

    

 

 

    

 

 

    

 

 

 

Not designated as hedging instruments:

           

Derivatives related to production not designated as hedging instruments

     33                 3         7   

Legacy natural gas contracts from former power business

     2        2        93         92   

All other

     20        13        60         47   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives not designated as hedging instruments

     55        15        156         146   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives

   $ 60      $ 15      $ 516       $ 159   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (“AOCI”) or revenues.

 

     Years Ended
December 31,
     Classification  
     2012      2011     
     (Millions)  

Net gain recognized in other comprehensive income (loss) (effective portion)

   $ 90      $ 413         AOCI   

Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(a)

   $ 434      $ 331         Revenues   

 

(a) Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains associated with our production reflected in natural gas sales and oil and condensate sales.

There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.

The following table presents pre-tax gains and losses recognized in revenues for our energy commodity derivatives not designated as hedging instruments.

 

     Years Ended
December 31,
 
     2012      2011  
     (Millions)  

Unrealized gain (loss)

   $ 32      $ (10

Realized gain (loss)

     46        39  
  

 

 

    

 

 

 

Net gain (loss) on derivative not designated as hedges

   $ 78      $ 29   
  

 

 

    

 

 

 

The cash flow impact of our derivative activities is presented in the Consolidated Statements of Cash Flows as changes in current and noncurrent derivative assets and liabilities.

Credit-risk-related features

Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.

As of December 31, 2012, we had collateral totaling $2 million posted to derivative counterparties to support the aggregate fair value of our net $5 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2011, we had collateral totaling $18 million posted to derivative counterparties to support the aggregate fair value of our net $37 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which included a reduction of less than $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $3 million and $19 million at December 31, 2012 and December 31, 2011, respectively.

Cash flow hedges

Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During the first quarter of 2012, approximately $15 million of unrealized gains were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett Shale properties. The $15 million gain is included in net gains (losses) on derivatives not designated as hedges on the Consolidated Statements of Operations for 2012, as are second-quarter 2012 changes in forward mark to market value. As of December 31, 2012, we have hedged portions of future cash flows associated with anticipated energy commodity sales for three months. Based on recorded values at December 31, 2012, $3 million of net gains (net of income tax provision of $2 million) will be reclassified into earnings in the first quarter of 2013. These recorded values are based on market prices of the commodities as of December 31, 2012. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next quarter could differ from these values. These gains or losses are expected to substantially offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts receivable

The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31:

 

     2012      2011  
     (Millions)  

Receivables by product or service:

     

Sale of natural gas and related products and services

   $ 289      $ 286   

Joint interest owners

     138        150   

Other

     16        11   
  

 

 

    

 

 

 

Total

   $ 443      $ 447   
  

 

 

    

 

 

 

Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and Gulf Coast. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

 

Derivative assets and liabilities

We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2012, 2011 and 2010, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.

The gross and net credit exposure from our derivative contracts as of December 31, 2012, is summarized as follows:

 

Counterparty Type

   Gross  Investment
Grade(a)
     Gross Total      Net
Investment

Grade(a)
     Net Total  
     (Millions)  

Gas and electric utilities, integrated oil and gas companies, and other

   $ 1       $ 1      $ 1      $ 1  

Energy marketers and traders

     5        5         4        5   

Financial institutions

     54        54         44        44   
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 60         60       $ 49        50   
  

 

 

    

 

 

    

 

 

    

 

 

 

Credit reserves

        —             —    
     

 

 

       

 

 

 

Credit exposure from derivatives

      $ 60          $ 50   
     

 

 

       

 

 

 

 

(a) We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Our eight largest net counterparty positions represent approximately 97 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.

At December 31, 2012, we held collateral support of $4 million, either in the form of cash or letters of credit, related to our other derivative positions.

Revenues

During 2012, 2011, and 2010, BP Energy Company, a domestic segment customer, accounted for 10 percent, 11 percent and 13 percent of our consolidated revenues, respectively. During 2012, Williams accounted for 12 percent of our consolidated revenue. Prior to 2012, Williams was considered an affiliate of WPX. See Note 3 for revenue related to Williams for 2011 and 2010. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

Segment Disclosures
Segment Disclosures

Note 17. Segment Disclosures

Our reporting segments are domestic and international (see Note 1).

Our segment presentation is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions. Domestic and international maintain separate capital and cash management structures. These factors, coupled with differences in the business environment associated with operating in different countries, serve to differentiate the management of this entity as a whole.

Performance Measurement

We evaluate performance based upon segment revenues and segment operating income (loss). There are no intersegment sales between domestic and international.

The following tables reflect the reconciliation of segment revenues and segment operating income (loss) to revenues and operating income (loss) as reported in the Consolidated Statements of Operations. Long-lived assets are comprised of gross property, plant and equipment and long-term investments.

 

For the year ended December 31, 2012    Domestic     International      Total  
           (Millions)         

Total revenues

   $ 3,052      $ 137       $ 3,189   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 251      $ 32       $ 283   

Gathering, processing and transportation

     504        2        506   

Taxes other than income

     87        24         111   

Gas management, including charges for unutilized pipeline capacity

     996        —           996   

Exploration

     72        11         83   

Depreciation, depletion and amortization

     939        27         966   

Impairment of producing properties and costs of acquired unproved reserves

     225        —          225   

General and administrative

     273        14         287   

Other—net

     12        —           12   
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 3,359      $ 110       $ 3,469   
  

 

 

   

 

 

    

 

 

 

Operating income (loss)

   $ (307   $ 27       $ (280

Interest expense

     (102     —          (102

Interest capitalized

     8        —          8   

Investment income and other

     3        27         30   
  

 

 

   

 

 

    

 

 

 

Income (loss) from continuing operations before income taxes

   $ (398   $ 54       $ (344
  

 

 

   

 

 

    

 

 

 

Other financial information:

       

Net capital expenditures

   $ 1,463      $ 58       $ 1,521   

Total assets

   $ 9,113      $ 343       $ 9,456   

Long—lived assets

   $ 13,056      $ 428       $ 13,484   

 

For the year ended December 31, 2011    Domestic     International      Total  
           (Millions)         

Total revenues

   $ 3,772      $ 110       $ 3,882   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 235      $ 27       $ 262   

Gathering, processing and transportation

     487        —          487   

Taxes other than income

     113        21         134   

Gas management, including charges for unutilized pipeline capacity

     1,471        —          1,471   

Exploration

     123        3         126   

Depreciation, depletion and amortization

     880        22         902   

Impairment of producing properties and costs of acquired unproved reserves

     367        —          367   

General and administrative

     263        12         275   

Other—net

     (3     3         —     
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 3,936      $ 88       $ 4,024   
  

 

 

   

 

 

    

 

 

 

Operating income (loss)

   $ (164   $ 22       $ (142

Interest expense

     (117     —          (117

Interest capitalized

     9        —          9   

Investment income and other

     6        20         26   
  

 

 

   

 

 

    

 

 

 

Income (loss) from continuing operations before income taxes

   $ (266   $ 42       $ (224
  

 

 

   

 

 

    

 

 

 

Other financial information:

       

Net capital expenditures

   $ 1,531      $ 41       $ 1,572   

Total assets

   $ 10,144      $ 288       $ 10,432   

Long-lived assets

   $ 11,969      $ 354       $ 12,323   

 

For the year ended December 31, 2010    Domestic     International      Total  
           (Millions)         

Total revenues

   $ 3,846      $ 89       $ 3,935   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 244      $ 19       $ 263   

Gathering, processing and transportation

     320        —          320   

Taxes other than income

     104        16         120   

Gas management, including charges for unutilized pipeline capacity

     1,767        —          1,767   

Exploration

     51        6         57   

Depreciation, depletion and amortization

     794        17         811   

Impairment of producing properties and costs of acquired unproved reserves

     175        —          175   

Goodwill impairment

     1,003        —          1,003   

General and administrative

     233        9         242   

Other—net

     (18     —          (18
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 4,673      $ 67       $ 4,740   
  

 

 

   

 

 

    

 

 

 

Operating income (loss)

   $ (827   $ 22       $ (805

Interest expense

     (124     —          (124

Interest capitalized

     15        —          15   

Investment income and other

     4        17         21   
  

 

 

   

 

 

    

 

 

 

Income (loss) from continuing operations before income taxes

   $ (932   $ 39       $ (893
  

 

 

   

 

 

    

 

 

 

Other financial information:

       

Net capital expenditures

   $ 1,821      $ 35       $ 1,856   

Total assets

   $ 9,590      $ 256       $ 9,846   

Long—lived assets

   $ 11,915      $ 306       $ 12,221   
QUARTERLY FINANCIAL DATA
QUARTERLY FINANCIAL DATA

WPX Energy, Inc.

QUARTERLY FINANCIAL DATA

(Unaudited)

Summarized quarterly financial data are as follows:

 

     First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
 
     (Millions, except per-share amounts)  

2012

  

Revenues

   $ 910     $ 775     $ 677     $ 827   

Operating costs and expenses

     834       673        680        758   

Income (loss) from continuing operations

     (38 )     (29     (63     (103

Net income (loss)

     (40 )     (6     (61     (104

Amounts attributable to WPX Energy:

        

Net income (loss)

     (43 )     (10     (64     (106

Basic and diluted earnings (loss) per common share:

        

Income (loss) from continuing operations

   $ (0.21 )   $ (0.17   $ (0.33   $ (0.53

2011

        

Revenues

   $ 958      $ 959      $ 995      $ 970   

Operating costs and expenses

     841        807        904        830   

Income (loss) from continuing operations

     7        30        19        (206

Net income (loss)

     (1     28        16        (335

Amounts attributable to WPX Energy:

        

Net income (loss)

     (3     25        14        (338

Basic and diluted earnings (loss) per common share:

        

Income (loss) from continuing operations

   $ 0.03      $ 0.13      $ 0.09      $ (1.06

The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.

Net loss for fourth-quarter 2012 includes the following pre-tax items:

 

   

$108 million of impairments of producing properties and costs of acquired unproved reserves (see Note 6).

Net loss for second-quarter 2012 includes the following pre-tax items:

 

   

$65 million of impairments of costs of acquired unproved reserves in the Powder River Basin (see Note 6).

 

   

Gain on sale of Barnett and Arkoma properties.

Net loss for first-quarter 2012 includes the following pre-tax items:

 

   

$52 million of impairments of costs of acquired unproved reserves primarily in the Powder River Basin (see Note 6).

Net loss for fourth-quarter 2011 includes the following pre-tax items:

 

   

$367 million of impairments of producing properties and costs of acquired unproved reserves (see Note 6) and $193 million of impairments related to the Barrett Shale and Arkoma discontinued operations (see Note 2).

Net income for third-quarter 2011 includes the following pre-tax items:

 

   

$50 million write-off of leasehold costs associated with approximately 65 percent of our Columbia County, Pennsylvania acreage;

 

   

$11 million of dry hole costs associated with an exploratory Marcellus Shale well in Columbia County.

Supplemental Oil and Gas Disclosures
Supplemental Oil and Gas Disclosures


WPX Energy, Inc.

Supplemental Oil and Gas Disclosures

(Unaudited)

We have significant oil and gas producing activities primarily in the Rocky Mountain region, North Dakota and Pennsylvannia in the United States. Additionally, we have international oil and gas producing activities, primarily in Argentina. The following information excludes our gas management activities.

With the exception of Capitalized Costs and the Results of Operations for all years presented, the following information includes information, through the date of sale, for the holdings in the Barnett Shale and Arkoma Basin which have been reported as discontinued operations in our consolidated financial statements. These operations represented less than five percent of our total domestic and international proved reserves in 2011.

Capitalized Costs

 

     As of December 31, 2011  
     Domestic     International     Consolidated
Total
    Entity’s share of
international
equity method
investee
 
     (Millions)  

Proved Properties

   $ 9,931      $ 259      $ 10,190      $ 254   

Unproved properties

     1,655        3        1,658        —    
  

 

 

   

 

 

   

 

 

   

 

 

 
     11,586        262        11,848        254   

Accumulated depreciation, depletion and amortization and valuation provisions

     (3,678     (133     (3,811     (154
  

 

 

   

 

 

   

 

 

   

 

 

 

Net capitalized costs

   $ 7,908      $ 129      $ 8,037      $ 100   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

     As of December 31, 2012  
     Domestic     International     Consolidated
Total
     Entity’s share of
international
equity method
investee
 
     (Millions)  

Proved Properties

   $ 11,295      $ 310      $ 11,605       $ 292   

Unproved properties

     1,153        9        1,162         1   
  

 

 

   

 

 

   

 

 

    

 

 

 
     12,448        319        12,767         293   

Accumulated depreciation, depletion and amortization and valuation provisions

     (4,612     (161     (4,773)         (181
  

 

 

   

 

 

   

 

 

    

 

 

 

Net capitalized costs

   $ 7,836      $ 158      $ 7,994       $ 112   
  

 

 

   

 

 

   

 

 

    

 

 

 

 

   

Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $436 million and $251 million, net, for 2012 and 2011, respectively.

 

   

Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.

 

   

Unproved properties consist primarily of unproved leasehold costs and costs for acquired unproved reserves.

 

Cost Incurred

 

     Domestic      International      Entity’s share of
international
equity method
investee
 
     (Millions)  

For the Year Ended December 31, 2010

        

Acquisition

   $ 1,731       $ —         $ —    

Exploration

     22         13         3   

Development

     988         27         25   
  

 

 

    

 

 

    

 

 

 
   $ 2,741       $ 40       $ 28   
  

 

 

    

 

 

    

 

 

 

For the Year Ended December 31, 2011

        

Acquisition

   $ 45       $ —        $ —    

Exploration

     31         20         8   

Development

     1,461         24         26