WPX ENERGY, INC., 10-Q filed on 5/7/2014
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2014
May 6, 2014
Document Documentand Entity Information [Abstract]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Mar. 31, 2014 
 
Document Fiscal Year Focus
2014 
 
Document Fiscal Period Focus
Q1 
 
Trading Symbol
WPX 
 
Entity Registrant Name
WPX ENERGY, INC. 
 
Entity Central Index Key
0001518832 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
202,150,303 
Consolidated Balance Sheet (Unaudited) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2014
Dec. 31, 2013
Current assets:
 
 
Cash and cash equivalents
$ 58 
$ 99 
Accounts receivable, net of allowance of $7 million at March 31, 2014 and December 31, 2013
664 
536 
Deferred income taxes
46 
49 
Derivative assets, current
25 
50 
Inventories
68 
72 
Margin deposits
72 
71 
Other
28 
45 
Total current assets
961 
922 
Investments
148 
145 
Properties and equipment (successful efforts method of accounting)
13,052 
12,686 
Less—accumulated depreciation, depletion and amortization
(5,654)
(5,445)
Properties and equipment, net
7,398 
7,241 
Derivative assets, noncurrent
17 
Other noncurrent assets
113 
114 
Total assets
8,637 
8,429 
Current liabilities:
 
 
Accounts payable
758 
652 
Accrued and other current liabilities
147 
190 
Customer margin deposits payable
12 
55 
Derivative liabilities, current
128 
110 
Total current liabilities
1,045 
1,007 
Deferred income taxes
807 
788 
Long-term debt
2,039 
1,916 
Derivative liabilities, noncurrent
12 
Asset retirement obligations
367 
358 
Other noncurrent liabilities
139 
138 
Contingent liabilities and commitments (Note 7)
   
   
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; 202.2 million shares issued at March 31, 2014 and 201 million shares issued at December 31, 2013)
Additional paid-in-capital
5,520 
5,516 
Accumulated deficit
(1,390)
(1,408)
Accumulated other comprehensive income (loss)
(1)
(1)
Total stockholders’ equity
4,131 
4,109 
Noncontrolling interests in consolidated subsidiaries
102 
101 
Total equity
4,233 
4,210 
Total liabilities and equity
$ 8,637 
$ 8,429 
Consolidated Balance Sheet (Unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Mar. 31, 2014
Dec. 31, 2013
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 7 
$ 7 
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
202,200,000 
201,000,000 
Consolidated Statement of Operations (Unaudited) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
Product revenues:
 
 
Natural gas sales
$ 384 
$ 267 
Oil and condensate sales
175 
139 
Natural Gas Liquid Sales
61 
54 
Total product revenues
620 
460 
Gas management
561 
261 
Net gain (loss) on derivatives not designated as hedges (Note 9)
(195)
(94)
Other
Total revenues
987 
631 
Costs and expenses:
 
 
Lease and facility operating
79 
75 
Gathering, processing and transportation
106 
107 
Taxes other than income
47 
35 
Gas management, including charges for unutilized pipeline capacity
391 
243 
Exploration (Note 3)
15 
19 
Depreciation, depletion and amortization
207 
231 
General and administrative
72 
72 
Other—net
Total costs and expenses
920 
789 
Operating income (loss)
67 
(158)
Interest expense
(29)
(26)
Interest capitalized
Investment income and other
Income (loss) before income taxes
42 
(176)
Provision (benefit) for income taxes
23 
(63)
Net income (loss)
19 
(113)
Less: Net income (loss) attributable to noncontrolling interests
Net income (loss) attributable to WPX Energy, Inc.
$ 18 
$ (116)
Earnings (loss) per common share:
 
 
Income (Loss) from Continuing Operations, Per Basic Share
$ 0.09 
$ (0.58)
Income (Loss) from Continuing Operations, Per Diluted Share
$ 0.09 
$ (0.58)
Weighted Average Number of Shares Outstanding, Basic
201.5 
199.9 
Weighted Average Number of Shares Outstanding, Diluted
205.2 
199.9 1
Consolidated Statement of Comprehensive Income (Loss) (Unaudited) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
 
 
Net income (loss) attributable to WPX Energy, Inc.
$ 18 
$ (116)
Other comprehensive income (loss):
 
 
Net reclassifications into earnings of net cash flow hedge realized gains, net of tax (a)
(3)
Other comprehensive income (loss), net of tax
(3)
Comprehensive income (loss) attributable to WPX Energy, Inc.
$ 18 
$ (119)
Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
 
Reclassification adjustment on derivatives included in net income, tax
$ 2 
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion) (a)
$ 5 
Consolidated Statement of Changes in Equity (Unaudited) (USD $)
In Millions, unless otherwise specified
Total
Common Stock
Additional Paid-In- Capital
Accumulated Deficit
Accumulated Other Comprehensive Income (Loss)
Total Stockholders’ Equity
Noncontrolling Interests in Consolidated Subsidiaries
December 31, 2013 at Dec. 31, 2013
$ 4,210 
$ 2 
$ 5,516 
$ (1,408)
$ (1)
$ 4,109 
$ 101 1
Comprehensive income (loss):
 
 
 
 
 
 
 
Net income (loss)
19 
 
 
18 
 
18 
1
Other comprehensive loss
 
 
 
 
Comprehensive income (loss)
19 
 
 
 
 
 
 
Stock based compensation
 
 
 
 
Contributions from Noncontrolling Interests
 
 
 
 
 
March 31, 2014 at Mar. 31, 2014
$ 4,233 
$ 2 
$ 5,520 
$ (1,390)
$ (1)
$ 4,131 
$ 102 1
Consolidated Statement of Changes in Equity (Parenthetical)
Mar. 31, 2014
Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
 
 
Noncontrolling interest, ownership percentage by noncontrolling owners
31.00% 
31.00% 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
Operating Activities
 
 
Net income (loss)
$ 19 
$ (113)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
207 
231 
Deferred income tax provision (benefit)
21 
(68)
Provision for impairment of properties and equipment (including certain exploration expenses)
11 
14 
Amortization of stock-based awards
Cash provided (used) by operating assets and liabilities:
 
 
Accounts receivable
(128)
33 
Inventories
12 
Margin deposits and customer margin deposit payable
(44)
(11)
Other current assets
20 
(9)
Accounts payable
104 
Accrued and other current liabilities
(51)
(63)
Changes in current and noncurrent derivative assets and liabilities
27 
103 
Other, including changes in other noncurrent assets and liabilities
Net cash provided by operating activities
206 
144 
Investing Activities
 
 
Capital expenditures
(352)1
(271)1
Other
(2)
Net cash used in investing activities
(354)
(271)
Financing Activities
 
 
Proceeds from common stock
Borrowings on credit facility
622 
80 
Payments on credit facility
(497)
Other
(17)
Net cash provided by financing activities
112 
87 
Net increase (decrease) in cash and cash equivalents
(36)
(40)
Effect of Exchange Rate on Cash and Cash Equivalents
(5)
(1)
Cash and cash equivalents at beginning of period
99 
153 
Cash and cash equivalents at end of period
58 
112 
Increase to properties and equipment
(372)
(277)
Changes in related accounts payable and accounts receivable
$ 20 
$ 6 
Basis of Presentation and Description of Business
Basis of Presentation and Description of Business
Basis of Presentation and Description of Business
Basis of Presentation
The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2013 in the Company’s Annual Report on Form 10-K. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at March 31, 2014, results of operations for the three months ended March 31, 2014 and 2013, changes in equity for the three months ended March 31, 2014 and cash flows for the three months ended March 31, 2014 and 2013.
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.
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 natural gas liquids (“NGL”) development, production and gas management activities located in Colorado, New Mexico, North Dakota, Pennsylvania and Wyoming in the United States. We specialize in development and production from tight-sands and shale formations and coal bed methane reserves in the Piceance, Williston, San Juan, Powder River, Appalachian and Green River Basins. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.
International primarily consists of our ownership in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with activities in Argentina and Colombia.
The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we”, “us” or “our”.
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share
The following table summarizes the calculation of earnings per share.
 
Three months
ended March 31,
 
2014
 
2013
 
(Millions, except per-share amounts)
Income (loss) attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
$
18

 
$
(116
)
Basic weighted-average shares
201.5

 
199.9

Effect of dilutive securities (a):
 
 
 
Nonvested restricted stock units and awards
2.7

 

Stock options
1.0

 

Diluted weighted-average shares
205.2

 
199.9

Earnings (loss) per common share:
 
 
 
Basic
$
0.09

 
$
(0.58
)
Diluted
$
0.09

 
$
(0.58
)

__________
(a) For the three months ended March 31, 2013, 1.9 million weighted-average nonvested restricted stock units and awards and 0.8 million 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. for the three months ended March 31, 2013.
The table below includes information related to stock options that were outstanding at March 31, 2014 and 2013 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the first quarter weighted-average market price of our common shares.
 
March 31,
 
2014
 
2013
Options excluded (millions)
0.4

 
1.8

Weighted-average exercise price of options excluded
$
20.23

 
$
17.50

Exercise price range of options excluded
$19.95 - $20.97

 
$15.67 - $20.97

First quarter weighted-average market price
$
18.44

 
$
15.27

Exploration Expense
Asset Sales Impairments Exploration Expenses And Other Accruals [Text Block]
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Three months
ended March 31,
 
2014
 
2013
 
(Millions)
Geologic and geophysical costs
$
5

 
$
5

Dry hole costs

 
1

Unproved leasehold property impairment, amortization and expiration
10

 
13

Total exploration expenses
$
15

 
$
19

Inventories
Inventories
Inventories 
 
March 31,
2014
 
December 31,
2013
 
(Millions)
Natural gas in underground storage
$

 
$
13

Crude oil production in transit
12

 
10

Material, supplies and other
56

 
49

 
$
68

 
$
72


During the first quarter of 2014, we sold our natural gas in underground storage.
Debt and Banking Arrangements
Debt and Banking Arrangements
Debt and Banking Arrangements
As of the indicated dates, our debt consisted of the following:
 
March 31,
2014
 
December 31,
2013
 
(Millions)
5.250% Senior Notes due 2017
$
400

 
$
400

6.000% Senior Notes due 2022
1,100

 
1,100

Credit facility agreement
535

 
410

Apco
8

 
8

Other
1

 
1

     Total debt
$
2,044

 
$
1,919

Less: Current portion of long-term debt
5

 
3

     Total long-term debt
$
2,039

 
$
1,916


We have a $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”) that expires in 2016. Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. As of March 31, 2014, the variable interest rate was 2.17 percent on the $535 million outstanding under the Credit Facility Agreement.
Letters of Credit
WPX has also 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 March 31, 2014, a total of $362 million in letters of credit have been issued.
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
The provision (benefit) for income taxes from continuing operations includes: 
 
Three months
ended March 31,
 
2014
 
2013
 
(Millions)
Current:
 
 
 
Federal
$
1

 
$
1

State

 

Foreign
1

 
4

 
2

 
5

Deferred:
 
 
 
Federal
6

 
(62
)
State
15

 
(6
)
Foreign

 

 
21

 
(68
)
Total provision (benefit)
$
23

 
$
(63
)

Tax reform legislation was enacted by the state of New York on March 31, 2014, and has an impact on us as a result of our marketing activities in the state. Key components of this reform measure relative to our business include water’s edge unitary combined reporting, single sales factor apportionment and the application of “economic nexus” to corporations with sales of $1 million or more to New York customers. Generally accepted accounting principles require that we adjust our state deferred tax liability for the estimated impact of this legislation in the period of enactment. As a result we recorded an additional $9 million of deferred tax expense in the first quarter to accrue for the impact of this new legislation.
The effective income tax rate of the total provision for the three months ended March 31, 2014, is greater than the federal statutory rate due primarily to state income taxes, partially offset by taxes on foreign operations.
The effective income tax rate of the total benefit for the three months ended March 31, 2013, is greater than the federal statutory rate due primarily to state income taxes, partially offset by taxes on foreign operations.
As of March 31, 2014, the amount of unrecognized tax benefits is not material. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with domestic or international matters will result in a significant increase or decrease of our unrecognized tax benefit.
Pursuant to our tax sharing agreement with The Williams Companies, Inc. (“Williams”) , we remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. We are not aware of any significant issues related to our business, but the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit issues unrelated to our business.
Contingent Liabilities
Contingent Liabilities
Contingent Liabilities
Royalty litigation
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs’ proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We are in the process of conducting an accounting under that standard. However, we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law.
In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraud, fraud concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs seek monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter has been removed to the United States District Court for New Mexico. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico, violation of the New Mexico Oil and Gas Proceeds Payment Act and seek declaratory judgment, accounting and injunction. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR’s predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From April 2007 through March 2014, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $109 million.
Environmental matters
The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Matters related to Williams’ former power business
In connection with the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending or threatened litigation described below relating to the 2000-2001 California energy crisis and the reporting of certain natural gas-related information to trade publications.
California energy crisis
Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the Federal Energy Regulatory Commission (“FERC”). We have entered into settlements with the State of California (“State Settlement”), major California utilities (“Utilities Settlement”) and others that substantially resolved each of these issues with these parties.
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We currently have a FERC approved settlement agreement with certain California utilities aimed at eliminating this exposure. Once implemented, the settlement agreement will also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement will resolve most, if not all, of our legal issues arising from the 2000-2001 California energy crisis. With respect to these matters, amounts accrued are not material to our financial position. 
Certain other issues also remain open at the FERC and for other nonsettling parties.
Reporting of natural gas-related information to trade publications
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order.
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion on the Western States Antitrust Litigation.  The panel held that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims, reversing the summary judgment entered in favor of the defendants.  The panel further held that the district court did not abuse its discretion in denying the plaintiffs’ motions for leave to amend complaints. Defendants’ filed a petition for writ of certiorari with the U.S. Supreme Court. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
At March 31, 2014, 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 March 31, 2014 and December 31, 2013, the Company had accrued approximately $16 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
Fair Value Measurements
Fair Value Measurements
Fair Value Measurements
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, and margin deposits and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
March 31, 2014
 
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$
15

 
$
27

 
$

 
$
42

 
$
30

 
$
26

 
$
1

 
$
57

Energy derivative liabilities
$
58

 
$
77

 
$

 
$
135

 
$
83

 
$
38

 
$
1

 
$
122

Total debt (a)
$

 
$
2,093

 
$

 
$
2,093

 
$

 
$
1,945

 
$

 
$
1,945

__________
(a)
The carrying value of total debt, excluding capital leases, was $2,043 million and $1,918 million as of March 31, 2014 and December 31, 2013, respectively.
Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Forward, swap and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with 100 percent of the net fair value of our derivatives portfolio expiring at the end of 2015. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a monthly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 were less than $1 million at March 31, 2014, and 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 occurred during the periods ended March 31, 2014 and 2013.
There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
 
 
 
 
Derivatives and Concentration of Credit Risk
Derivatives and Concentration of Credit Risk
 Derivatives and Concentration of Credit Risk
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas, oil and natural gas liquids attributable to commodity price risk. Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we entered into commodity derivative contracts that continued to serve as economic hedges but were not designated as cash flow hedges for accounting purposes as we elected not to utilize this method of accounting on new derivatives instruments. Remaining commodity derivatives recorded at December 31, 2011 that were designated as cash flow hedges were fully realized by the end of the first quarter of 2013.
We produce, buy and sell natural gas, crude oil and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas, crude oil and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions.
We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation and storage contracts economically hedge the expected cash flows generated by those agreements.
The following table sets forth the derivative notional volumes that are economic hedges of production volumes as well as notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, both which are included in our commodity derivatives portfolio as of March 31, 2014.
  Derivatives related to production
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
Crude Oil
 
Apr-Dec 2014
 
Fixed Price Swaps
 
WTI
 
(12,750
)
 
$
94.62

Crude Oil
 
Apr-Dec 2014
 
Basis Swaps
 
Brent
 
(2,978
)
 
$
9.64

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

Natural Gas
 
Apr-Dec 2014
 
Swaptions
 
Henry Hub
 
(50
)
 
$
4.24

Natural Gas
 
Apr-Dec 2014
 
Costless Collars
 
Henry Hub
 
(190
)
 
$ 4.04 - 4.66

Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
Northeast
 
(89
)
 
$
(0.73
)
Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
MidCon
 
(220
)
 
$
(0.18
)
Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
Rockies
 
(110
)
 
$
(0.18
)
Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
West
 
(55
)
 
$
0.10

NGL Ethane
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(3,273
)
 
$
0.29

NGL Propane
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(491
)
 
$
1.17

NGL Iso Butane
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(655
)
 
$
1.37

NGL Normal Butane
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(327
)
 
$
1.38

NGL Natural Gasoline
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(1,636
)
 
$
2.06

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

Natural Gas
 
2015
 
Fixed Price Swaps
 
Henry Hub
 
(180
)
 
$
4.34

Natural Gas
 
2015
 
Swaptions
 
Henry Hub
 
(50
)
 
$
4.38

Natural Gas
 
2015
 
Costless Collars
 
Henry Hub
 
(50
)
 
$ 4.00 - 4.50

 
Derivatives primarily related to storage and transportation
Commodity
 
Period
 
Contract Type (d)
 
Location (e)
 
Notional Volume (b)
 
Weighted Average
Price (f)
Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
Multiple
 
(38
)
 
Natural Gas
 
Apr-Dec 2014
 
Index
 
Multiple
 
(151
)
 
Natural Gas
 
2015
 
Basis Swaps
 
Multiple
 
(8
)
 
Natural Gas
 
2015
 
Index
 
Multiple
 
(115
)
 
Natural Gas
 
2016
 
Index
 
Multiple
 
(70
)
 
Natural Gas
 
  2017+
 
Index
 
Multiple
 
(478
)
 
__________
(a)
Derivatives related to crude oil production are business day average swaps, basis swaps, and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. The derivatives related to natural gas liquids are fixed price swaps. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.
(b)
Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
(c)
The weighted average price for natural gas is reported in $/MMBtu, the crude oil price is reported in $/Bbl and natural gas liquids are reported in $/Gallon.
(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 primarily 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.
 
March 31, 2014
 
December 31, 2013
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production not designated as hedging instruments
$
27

 
$
77

 
$
26

 
$
39

Derivatives related to physical marketing agreements not designated as hedging instruments
15

 
58

 
31

 
83

Total derivatives not designated as hedging instruments
$
42

 
$
135

 
$
57

 
$
122


 
During the first quarter of 2013, we reclassified $5 million of net gain on derivatives designated as cash flow hedges from accumulated other comprehensive income (loss) into income. These gains primarily represent realized gains on derivatives designated as hedges of our production and are reflected in natural gas 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 the net gain (loss) related to our energy commodity derivatives.
 
Three months ended March 31,
 
2014
 
2013
 
(Millions)
Gain (loss) from derivatives related to production not designated as hedging instruments (a)
$
(86
)
 
$
(89
)
Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)
(109
)
 
(5
)
Net gain (loss) on derivatives not designated as hedges
$
(195
)
 
$
(94
)

__________
(a)
Includes payment of $50 million for settlement of derivatives during the three months ended March 31, 2014 and receipt of $5 million for the three months ended March 31, 2013.
(b)
Includes payment of $118 million for settlement of derivatives during the three months ended March 31, 2014 and receipt of $4 million for the three months ended March 31, 2013.
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.
Offsetting of derivative assets and liabilities
The following table presents our gross and net derivative assets and liabilities.
 
Gross Amount Presented on Balance Sheet
 
Netting Adjustments (a)
 
Cash Collateral Posted (Received)
 
Net Amount
March 31, 2014
(Millions)
Derivative assets with right of offset or master netting agreements
$
42

 
$
(41
)
 
$

 
$
1

Derivative liabilities with right of offset or master netting agreements
$
(135
)
 
$
41

 
$
43

 
$
(51
)
 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
57

 
$
(50
)
 
$

 
$
7

Derivative liabilities with right of offset or master netting agreements
$
(122
)
 
$
50

 
$
52

 
$
(20
)
__________
(a)
With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
Credit-risk-related features
Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.
As of March 31, 2014, we had collateral totaling $98 million ($72 million in cash and the remainder in letters of credit) posted to derivative counterparties, which included $55 million of initial margin to clearinghouses or exchanges to enter into positions and $43 million of maintenance margin for changes in the fair value of those positions, to support the aggregate fair value of our net $94 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. 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 $51 million at March 31, 2014. 
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.

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 2014 and 2013, 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 March 31, 2014, is summarized as follows:
Counterparty Type
Gross Investment
Grade  (a)
 
Gross Total
 
Net Investment
Grade  (a)
 
Net Total
 
(Millions)
Financial institutions
$
42

 
$
42

 
$
1

 
$
1

 
$
42

 
42

 
$
1

 
1

Credit reserves
 
 

 
 
 

Credit exposure from derivatives
 
 
$
42

 
 
 
$
1

 
__________
(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 four largest net counterparty positions represent approximately 90 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.
Other
At March 31, 2014, we held collateral support of approximately $69 million ($12 million in cash and the remainder in letters of credit) related to our gas management sales agreements.
Segment Disclosures
Segment Disclosures
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.
 
 
 
 
 
 
 
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Three months ended March 31, 2014
 
 
 
 
 
Total revenues
$
956

 
$
31

 
$
987

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
71

 
$
8

 
$
79

Gathering, processing and transportation
106

 

 
106

Taxes other than income
41

 
6

 
47

Gas management, including charges for unutilized pipeline capacity
391

 

 
391

Exploration
15

 

 
15

Depreciation, depletion and amortization
197

 
10

 
207

General and administrative
68

 
4

 
72

Other—net
2

 
1

 
3

Total costs and expenses
$
891

 
$
29

 
$
920

Operating income (loss)
$
65

 
$
2

 
$
67

Interest expense
(29
)
 

 
(29
)
Interest capitalized

 

 

Investment income and other
2

 
2

 
4

Income (loss) before income taxes
$
38

 
$
4

 
$
42

 
 
 
 
 
 
Three months ended March 31, 2013
 
 
 
 
 
Total revenues
$
595

 
$
36

 
$
631

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
67

 
$
8

 
$
75

Gathering, processing and transportation
106

 
1

 
107

Taxes other than income
29

 
6

 
35

Gas management, including charges for unutilized pipeline capacity
243

 

 
243

Exploration
18

 
1

 
19

Depreciation, depletion and amortization
224

 
7

 
231

General and administrative
69

 
3

 
72

Other—net
6

 
1

 
7

Total costs and expenses
$
762

 
$
27

 
$
789

Operating income (loss)
$
(167
)
 
$
9

 
$
(158
)
Interest expense
(26
)
 

 
(26
)
Interest capitalized
1

 

 
1

Investment income and other
2

 
5

 
7

Income (loss) before income taxes
$
(190
)
 
$
14

 
$
(176
)
 
 
 
 
 
 
Total assets
 
 
 
 
 
Total assets as of March 31, 2014
$
8,257

 
$
380

 
$
8,637

Total assets as of December 31, 2013
$
8,046

 
$
383

 
$
8,429

Subsequent Events (Notes)
Subsequent Events [Text Block]
Subsequent Events
On May 6, 2014, we announced an agreement to sell portions of our working interests in certain Piceance Basin wells to Legacy Reserves LP for $355 million cash, subject to closing adjustments and based on an effective date of January 1, 2014. The parties expect to close the sale during the second quarter 2014. The working interests represent approximately 300 billion cubic feet equivalent of proved reserves, or approximately 6 percent of WPX’s year-end 2013 proved reserves. The sale will result in a loss on sale which is currently estimated to be in the range of $200 million to $250 million. Upon the closing of this transaction, we expect to have access to approximately 90 percent of our $1.5 billion Credit Facility Agreement. One of the calculations to determine available borrowing capacity is the requirement to maintain a ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness of at least 1.50 to 1.00.
Earnings (Loss) Per Common Share from Continuing Operations (Tables)
The following table summarizes the calculation of earnings per share.
 
Three months
ended March 31,
 
2014
 
2013
 
(Millions, except per-share amounts)
Income (loss) attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
$
18

 
$
(116
)
Basic weighted-average shares
201.5

 
199.9

Effect of dilutive securities (a):
 
 
 
Nonvested restricted stock units and awards
2.7

 

Stock options
1.0

 

Diluted weighted-average shares
205.2

 
199.9

Earnings (loss) per common share:
 
 
 
Basic
$
0.09

 
$
(0.58
)
Diluted
$
0.09

 
$
(0.58
)

__________
(a) For the three months ended March 31, 2013, 1.9 million weighted-average nonvested restricted stock units and awards and 0.8 million 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. for the three months ended March 31, 2013.
The table below includes information related to stock options that were outstanding at March 31, 2014 and 2013 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the first quarter weighted-average market price of our common shares.
 
March 31,
 
2014
 
2013
Options excluded (millions)
0.4

 
1.8

Weighted-average exercise price of options excluded
$
20.23

 
$
17.50

Exercise price range of options excluded
$19.95 - $20.97

 
$15.67 - $20.97

First quarter weighted-average market price
$
18.44

 
$
15.27

Exploration Expense (Tables)
Exploration Expenses
The following table presents a summary of exploration expenses.
 
Three months
ended March 31,
 
2014
 
2013
 
(Millions)
Geologic and geophysical costs
$
5

 
$
5

Dry hole costs

 
1

Unproved leasehold property impairment, amortization and expiration
10

 
13

Total exploration expenses
$
15

 
$
19

Inventories (Tables)
Inventories
Inventories 
 
March 31,
2014
 
December 31,
2013
 
(Millions)
Natural gas in underground storage
$

 
$
13

Crude oil production in transit
12

 
10

Material, supplies and other
56

 
49

 
$
68

 
$
72

Debt and Banking Arrangements (Tables)
Schedule of Long-term Debt Instruments
As of the indicated dates, our debt consisted of the following:
 
March 31,
2014
 
December 31,
2013
 
(Millions)
5.250% Senior Notes due 2017
$
400

 
$
400

6.000% Senior Notes due 2022
1,100

 
1,100

Credit facility agreement
535

 
410

Apco
8

 
8

Other
1

 
1

     Total debt
$
2,044

 
$
1,919

Less: Current portion of long-term debt
5

 
3

     Total long-term debt
$
2,039

 
$
1,916

Provision (Benefit) for Income Taxes (Tables)
Provision (Benefit) for Income Taxes from Continuing Operations
The provision (benefit) for income taxes from continuing operations includes: 
 
Three months
ended March 31,
 
2014
 
2013
 
(Millions)
Current:
 
 
 
Federal
$
1

 
$
1

State

 

Foreign
1

 
4

 
2

 
5

Deferred:
 
 
 
Federal
6

 
(62
)
State
15

 
(6
)
Foreign

 

 
21

 
(68
)
Total provision (benefit)
$
23

 
$
(63
)
Fair Value Measurements (Tables)
Assets and Liabilities Measured at Fair Value on Recurring Basis
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, and margin deposits and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
March 31, 2014
 
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$
15

 
$
27

 
$

 
$
42

 
$
30

 
$
26

 
$
1

 
$
57

Energy derivative liabilities
$
58

 
$
77

 
$

 
$
135

 
$
83

 
$
38

 
$
1

 
$
122

Total debt (a)
$

 
$
2,093

 
$

 
$
2,093

 
$

 
$
1,945

 
$

 
$
1,945

__________
(a)
The carrying value of total debt, excluding capital leases, was $2,043 million and $1,918 million as of March 31, 2014 and December 31, 2013, respectively.
Derivatives and Concentration of Credit Risk (Tables)
The following table sets forth the derivative notional volumes that are economic hedges of production volumes as well as notional volumes of the net long (short) positions of derivatives primarily related to storage and transportation contracts, both which are included in our commodity derivatives portfolio as of March 31, 2014.
  Derivatives related to production
Commodity
 
Period
 
Contract Type (a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price (c)
Crude Oil
 
Apr-Dec 2014
 
Fixed Price Swaps
 
WTI
 
(12,750
)
 
$
94.62

Crude Oil
 
Apr-Dec 2014
 
Basis Swaps
 
Brent
 
(2,978
)
 
$
9.64

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

Natural Gas
 
Apr-Dec 2014
 
Swaptions
 
Henry Hub
 
(50
)
 
$
4.24

Natural Gas
 
Apr-Dec 2014
 
Costless Collars
 
Henry Hub
 
(190
)
 
$ 4.04 - 4.66

Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
Northeast
 
(89
)
 
$
(0.73
)
Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
MidCon
 
(220
)
 
$
(0.18
)
Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
Rockies
 
(110
)
 
$
(0.18
)
Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
West
 
(55
)
 
$
0.10

NGL Ethane
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(3,273
)
 
$
0.29

NGL Propane
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(491
)
 
$
1.17

NGL Iso Butane
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(655
)
 
$
1.37

NGL Normal Butane
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(327
)
 
$
1.38

NGL Natural Gasoline
 
Apr-Dec 2014
 
Fixed Price Swaps
 
Mont Belvieu
 
(1,636
)
 
$
2.06

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

Natural Gas
 
2015
 
Fixed Price Swaps
 
Henry Hub
 
(180
)
 
$
4.34

Natural Gas
 
2015
 
Swaptions
 
Henry Hub
 
(50
)
 
$
4.38

Natural Gas
 
2015
 
Costless Collars
 
Henry Hub
 
(50
)
 
$ 4.00 - 4.50

 
Derivatives primarily related to storage and transportation
Commodity
 
Period
 
Contract Type (d)
 
Location (e)
 
Notional Volume (b)
 
Weighted Average
Price (f)
Natural Gas
 
Apr-Dec 2014
 
Basis Swaps
 
Multiple
 
(38
)
 
Natural Gas
 
Apr-Dec 2014
 
Index
 
Multiple
 
(151
)
 
Natural Gas
 
2015
 
Basis Swaps
 
Multiple
 
(8
)
 
Natural Gas
 
2015
 
Index
 
Multiple
 
(115
)
 
Natural Gas
 
2016
 
Index
 
Multiple
 
(70
)
 
Natural Gas
 
  2017+
 
Index
 
Multiple
 
(478
)
 
__________
(a)
Derivatives related to crude oil production are business day average swaps, basis swaps, and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. The derivatives related to natural gas liquids are fixed price swaps. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.
(b)
Natural gas volumes are reported in BBtu/day, crude oil volumes are reported in Bbl/day, and natural gas liquids are reported in Bbl/day.
(c)
The weighted average price for natural gas is reported in $/MMBtu, the crude oil price is reported in $/Bbl and natural gas liquids are reported in $/Gallon.
(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 primarily 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.
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.
 
March 31, 2014
 
December 31, 2013
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production not designated as hedging instruments
$
27

 
$
77

 
$
26

 
$
39

Derivatives related to physical marketing agreements not designated as hedging instruments
15

 
58

 
31

 
83

Total derivatives not designated as hedging instruments
$
42

 
$
135

 
$
57

 
$
122

The following table presents the net gain (loss) related to our energy commodity derivatives.
 
Three months ended March 31,
 
2014
 
2013
 
(Millions)
Gain (loss) from derivatives related to production not designated as hedging instruments (a)
$
(86
)
 
$
(89
)
Gain (loss) from derivatives related to physical marketing agreements not designated as hedging instruments (b)
(109
)
 
(5
)
Net gain (loss) on derivatives not designated as hedges
$
(195
)
 
$
(94
)

__________
(a)
Includes payment of $50 million for settlement of derivatives during the three months ended March 31, 2014 and receipt of $5 million for the three months ended March 31, 2013.
(b)
Includes payment of $118 million for settlement of derivatives during the three months ended March 31, 2014 and receipt of $4 million for the three months ended March 31, 2013.
The following table presents our gross and net derivative assets and liabilities.
 
Gross Amount Presented on Balance Sheet
 
Netting Adjustments (a)
 
Cash Collateral Posted (Received)
 
Net Amount
March 31, 2014
(Millions)
Derivative assets with right of offset or master netting agreements
$
42

 
$
(41
)
 
$

 
$
1

Derivative liabilities with right of offset or master netting agreements
$
(135
)
 
$
41

 
$
43

 
$
(51
)
 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
57

 
$
(50
)
 
$

 
$
7

Derivative liabilities with right of offset or master netting agreements
$
(122
)
 
$
50

 
$
52

 
$
(20
)
__________
(a)
With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
The gross and net credit exposure from our derivative contracts as of March 31, 2014, is summarized as follows:
Counterparty Type
Gross Investment
Grade  (a)
 
Gross Total
 
Net Investment
Grade  (a)
 
Net Total
 
(Millions)
Financial institutions
$
42

 
$
42

 
$
1

 
$
1

 
$
42

 
42

 
$
1

 
1

Credit reserves
 
 

 
 
 

Credit exposure from derivatives
 
 
$
42

 
 
 
$
1

 
__________
(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.
Segment Disclosures (Tables)
Reconciliation of Segment Revenues and Segment Operating Income (Loss)
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.
 
 
 
 
 
 
 
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Three months ended March 31, 2014
 
 
 
 
 
Total revenues
$
956

 
$
31

 
$
987

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
71

 
$
8

 
$
79

Gathering, processing and transportation
106

 

 
106

Taxes other than income
41

 
6

 
47

Gas management, including charges for unutilized pipeline capacity
391

 

 
391

Exploration
15

 

 
15

Depreciation, depletion and amortization
197

 
10

 
207

General and administrative
68

 
4

 
72

Other—net
2

 
1

 
3

Total costs and expenses
$
891

 
$
29

 
$
920

Operating income (loss)
$
65

 
$
2

 
$
67

Interest expense
(29
)
 

 
(29
)
Interest capitalized

 

 

Investment income and other
2

 
2

 
4

Income (loss) before income taxes
$
38

 
$
4

 
$
42

 
 
 
 
 
 
Three months ended March 31, 2013
 
 
 
 
 
Total revenues
$
595

 
$
36

 
$
631

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
67

 
$
8

 
$
75

Gathering, processing and transportation
106

 
1

 
107

Taxes other than income
29

 
6

 
35

Gas management, including charges for unutilized pipeline capacity
243

 

 
243

Exploration
18

 
1

 
19

Depreciation, depletion and amortization
224

 
7

 
231

General and administrative
69

 
3

 
72

Other—net
6

 
1

 
7

Total costs and expenses
$
762

 
$
27

 
$
789

Operating income (loss)
$
(167
)
 
$
9

 
$
(158
)
Interest expense
(26
)
 

 
(26
)
Interest capitalized
1

 

 
1

Investment income and other
2

 
5

 
7

Income (loss) before income taxes
$
(190
)
 
$
14

 
$
(176
)
 
 
 
 
 
 
Total assets
 
 
 
 
 
Total assets as of March 31, 2014
$
8,257

 
$
380

 
$
8,637

Total assets as of December 31, 2013
$
8,046

 
$
383

 
$
8,429

Earnings (Loss) Per Common Share from Continuing Operations (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
Diluted (in dollars per share)
$ 0.09 
$ (0.58)
Basic (in dollars per share)
$ 0.09 
$ (0.58)
Weighted Average Number of Shares Outstanding, Diluted
205.2 
199.9 1
Weighted Average Number of Shares Outstanding, Basic
201.5 
199.9 
Income (Loss) from Continuing Operations Attributable to Parent
$ 18 
$ (116)
Non Vested Restricted Stock Units [Member]
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements
2.7 
 
Employee Stock Option [Member]
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements
1.0 
 
Non Vested Restricted Stock Units [Member]
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
 
1.9 
Employee Stock Option [Member]
 
 
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
 
0.8 
Earnings (Loss) Per Common Share from Continuing Operations (Details 1) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
Earnings Per Share [Abstract]
 
 
Options excluded (millions)
0.4 
1.8 
Weighted-average exercise price of options excluded
$ 20.23 
$ 17.50 
Exercise price range of options excluded, lower limit
$ 19.95 
$ 15.67 
Exercise price range of options excluded, upper limit
$ 20.97 
$ 20.97 
First quarter weighted-average market price
$ 18.44 
$ 15.27 
Exploration Expense (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2014
Mar. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
 
 
Geologic and geophysical costs
$ 5 
$ 5 
Dry hole costs
Unproved leasehold property impairment, amortization and expiration
10 
13 
Total exploration expenses
$ 15 
$ 19 
Inventories (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2014
Dec. 31, 2013
Inventory Disclosure [Abstract]
 
 
Natural gas in underground storage
$ 0 
$ 13 
Crude oil production in transit
12 
10 
Material, supplies and other
56 
49 
Inventory, Total
$ 68 
$ 72 
Debt and Banking Arrangements (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2014