10-Q 1 d621298d10q.htm 10-Q 10-Q
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

 

 

(Mark One)

 

[X]

 

    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

                                SECURITIES EXCHANGE ACT OF 1934

 
 

For the quarterly period ended             September  30, 2013                                                                 

  or
 

[    ]

 

    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

                                SECURITIES EXCHANGE ACT OF 1934

 
     
 

For the transition period from                                                   to                                                              

 

Commission file number:                              001-32395                                                                            

 

ConocoPhillips

(Exact name of registrant as specified in its charter)

 

Delaware  

            01-0562944

(State or other jurisdiction of  

        (I.R.S. Employer

incorporation or organization)  

        Identification No.)

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices)             (Zip Code)

281-293-1000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [    ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [    ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  [X]    Accelerated filer  [    ]     Non-accelerated filer  [    ]     Smaller reporting company  [    ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [    ] No [X]

The registrant had 1,225,098,698 shares of common stock, $.01 par value, outstanding at September 30, 2013.


Table of Contents

CONOCOPHILLIPS

TABLE OF CONTENTS

 

     Page  

Part I – Financial Information

  

    Item 1. Financial Statements

  

Consolidated Income Statement

     1   

Consolidated Statement of Comprehensive Income

     2   

Consolidated Balance Sheet

     3   

Consolidated Statement of Cash Flows

     4   

Notes to Consolidated Financial Statements

     5   

Supplementary Information—Condensed Consolidating Financial Information

     27   

    Item  2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     32   

    Item 3. Quantitative and Qualitative Disclosures About Market Risk

     53   

    Item 4. Controls and Procedures

     53   

Part II – Other Information

  

    Item 1. Legal Proceedings

     54   

    Item 1A. Risk Factors

     54   

    Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

     55   

    Item 6. Exhibits

     56   

Signature

     57   


Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

 

 

Consolidated Income Statement    ConocoPhillips

 

     Millions of Dollars  
     Three Months Ended     Nine Months Ended  
     September 30     September 30  
     2013       2012        2013       2012   
  

 

 

   

 

 

 

Revenues and Other Income

        

Sales and other operating revenues

   $ 13,643       14,141        41,159       42,398   

Equity in earnings of affiliates

     709       412        1,565       1,431   

Gain on dispositions

     1,069       118        1,222       1,641   

Other income

     49       42        317       168   

 

 

Total Revenues and Other Income

     15,470       14,713        44,263       45,638   

 

 

 

Costs and Expenses

        

Purchased commodities

     5,708       6,357        17,063       18,156   

Production and operating expenses

     1,962       1,637        5,321       4,998   

Selling, general and administrative expenses

     249       329        607       890   

Exploration expenses

     313       215        911       1,155   

Depreciation, depletion and amortization

     1,902       1,650        5,541       4,801   

Impairments

     1             31       296   

Taxes other than income taxes

     664       673        2,198       2,668   

Accretion on discounted liabilities

     106       100        317       308   

Interest and debt expense

     151       161        420       548   

Foreign currency transaction (gains) losses

     9             (34     17   

 

 

Total Costs and Expenses

     11,065       11,122        32,375       33,837   

 

 

Income from continuing operations before income taxes

     4,405       3,591        11,888       11,801   

Provision for income taxes

     1,966       1,851        5,359       6,162   

 

 

Income From Continuing Operations

     2,439       1,740        6,529       5,639   

Income from discontinued operations*

     57       73        183       1,418   

 

 

Net income

     2,496       1,813        6,712       7,057   

Less: net income attributable to noncontrolling interests

     (16     (15)        (43     (55)   

 

 

Net Income Attributable to ConocoPhillips

   $ 2,480       1,798        6,669       7,002   

 

 

Amounts Attributable to ConocoPhillips Common Shareholders:

        

Income from continuing operations

   $ 2,423       1,725        6,486       5,586   

Income from discontinued operations

     57       73        183       1,416   

 

 

Net income

   $ 2,480       1,798        6,669       7,002   

 

 

 

Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)

        

Basic

        

Continuing operations

   $ 1.96       1.41        5.26       4.47   

Discontinued operations

     0.05       0.06        0.15       1.13   

 

 

Net Income Attributable to ConocoPhillips Per Share of Common Stock

   $ 2.01       1.47        5.41       5.60   

 

 

Diluted

        

Continuing operations

   $ 1.95       1.40        5.23       4.43   

Discontinued operations

     0.05       0.06        0.15       1.12   

 

 

Net Income Attributable to ConocoPhillips Per Share of Common Stock

   $ 2.00       1.46        5.38       5.55   

 

 

 

Dividends Paid Per Share of Common Stock (dollars)

   $ 0.69       0.66        2.01       1.98   

 

 

 

Average Common Shares Outstanding (in thousands)

        

Basic

         1,231,054       1,220,462        1,230,027       1,250,641   

Diluted

     1,240,365       1,229,343        1,238,943       1,260,212   

 

 
*Net of provision for income taxes on discontinued operations of:    $ 136       94        215       885   

See Notes to Consolidated Financial Statements.

 

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Table of Contents

 

Consolidated Statement of Comprehensive Income    ConocoPhillips

 

     Millions of Dollars  
     Three Months Ended      Nine Months Ended  
     September 30      September 30  
     2013       2012         2013       2012   
  

 

 

    

 

 

 

Net Income

   $ 2,496       1,813         6,712       7,057   

Other comprehensive income (loss)

         

Defined benefit plans

         

Prior service cost arising during the period

     -                -          

Reclassification adjustment for amortization of prior service credit included in net income

     (1     (1)         (4     (3)   

 

 

Net change

     (1     (1)         (4     (3)   

 

 

Net actuarial gain (loss) arising during the period

     301       (432)         302       (470)   

Reclassification adjustment for amortization of net actuarial losses included in net income

     106       189         220       327   

 

 

Net change

     407       (243)         522       (143)   

Nonsponsored plans*

     -                1        

Income taxes on defined benefit plans

     (155     94         (197     67   

 

 

Defined benefit plans, net of tax

     251       (150)         322       (74)   

 

 

Unrealized holding gain on securities

     -                -         

Income taxes on unrealized holding gain on securities

     -                -          

 

 

Unrealized gain on securities, net of tax

     -                -         

 

 

Foreign currency translation adjustments

     623       925         (1,705     1,244   

Reclassification adjustment for loss included in net income

     -        (320)         (4     (319)   

Income taxes on foreign currency translation adjustments

     (2            12       21   

 

 

Foreign currency translation adjustments, net of tax

     621       612         (1,697     946   

 

 

Hedging activities

     -                -         

Income taxes on hedging activities

     -                -          

 

 

Hedging activities, net of tax

     -                -         

 

 

Other Comprehensive Income (Loss), Net of Tax

     872       462         (1,375     879   

 

 

Comprehensive Income

     3,368       2,275         5,337       7,936   

Less: comprehensive income attributable to noncontrolling interests

     (16     (15)         (43     (55)   

 

 

Comprehensive Income Attributable to ConocoPhillips

   $     3,352       2,260         5,294       7,881   

 

 

*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.

See Notes to Consolidated Financial Statements.

 

2


Table of Contents

 

Consolidated Balance Sheet    ConocoPhillips

 

     Millions of Dollars  
     September 30     December 31  
     2013     2012  
  

 

 

 

Assets

    

Cash and cash equivalents

   $ 3,883       3,618   

Restricted cash

     -        748   

Accounts and notes receivable (net of allowance of $9 million in 2013 and $10 million in 2012)

     8,191       8,929   

Accounts and notes receivable—related parties

     214       253   

Inventories

     1,268       965   

Prepaid expenses and other current assets

     9,001       9,476   

 

 

Total Current Assets

     22,557       23,989   

Investments and long-term receivables

     23,792       23,489   

Loans and advances—related parties

     1,374       1,517   

Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $63,399 million in 2013 and $58,916 million in 2012)

     71,129       67,263   

Other assets

     908       886   

 

 

Total Assets

   $ 119,760       117,144   

 

 

Liabilities

    

Accounts payable

   $ 9,411       9,154   

Accounts payable—related parties

     922       859   

Short-term debt

     572       955   

Accrued income and other taxes

     2,911       3,366   

Employee benefit obligations

     678       742   

Other accruals

     1,841       2,367   

 

 

Total Current Liabilities

     16,335       17,443   

Long-term debt

     21,096       20,770   

Asset retirement obligations and accrued environmental costs

     9,159       8,947   

Joint venture acquisition obligation—related party

     2,203       2,810   

Deferred income taxes

     14,745       13,185   

Employee benefit obligations

     2,847       3,346   

Other liabilities and deferred credits

     1,838       2,216   

 

 

Total Liabilities

     68,223       68,717   

 

 

Equity

    

Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2013—1,767,329,371 shares; 2012—1,762,247,949 shares)

    

Par value

     18       18   

Capital in excess of par

     45,637       45,324   

Treasury stock (at cost: 2013—542,230,673 shares; 2012—542,230,673 shares)

     (36,780     (36,780)   

Accumulated other comprehensive income

     2,712       4,087   

Retained earnings

     39,526       35,338   

 

 

Total Common Stockholders’ Equity

     51,113       47,987   

Noncontrolling interests

     424       440   

 

 

Total Equity

     51,537       48,427   

 

 

Total Liabilities and Equity

   $ 119,760       117,144   

 

 

See Notes to Consolidated Financial Statements.

 

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Table of Contents

 

Consolidated Statement of Cash Flows    ConocoPhillips

 

     Millions of Dollars  
     Nine Months Ended
September 30
 
     2013     2012   
  

 

 

 

Cash Flows From Operating Activities

    

Net income

   $         6,712               7,057   

Adjustments to reconcile net income to net cash provided by operating activities

    

Depreciation, depletion and amortization

     5,541       4,801   

Impairments

     31       296   

Dry hole costs and leasehold impairments

     345       703   

Accretion on discounted liabilities

     317       308   

Deferred taxes

     1,142       811   

Undistributed equity earnings

     (585     (409)   

Gain on dispositions

     (1,222     (1,641)   

Income from discontinued operations

     (183     (1,418)   

Other

     (280     (53)   

Working capital adjustments

    

Decrease (increase) in accounts and notes receivable

     822       (1,762)   

Decrease (increase) in inventories

     (301      

Decrease (increase) in prepaid expenses and other current assets

     (172     376   

Increase in accounts payable

     324       1,024   

Decrease in taxes and other accruals

     (550     (506)   

 

 

Net cash provided by continuing operating activities

     11,941       9,588   

Net cash provided by discontinued operations

     235       464   

 

 

Net Cash Provided by Operating Activities

     12,176       10,052   

 

 

Cash Flows From Investing Activities

    

Capital expenditures and investments

     (11,281     (10,720)   

Proceeds from asset dispositions

     3,175       2,088   

Net sales of short-term investments

     1       597   

Collection of advances/loans—related parties

     130       100   

Other

     (51     175   

 

 

Net cash used in continuing investing activities

     (8,026     (7,760)   

Net cash used in discontinued operations

     (540     (938)   

 

 

Net Cash Used in Investing Activities

     (8,566     (8,698)   

 

 

Cash Flows From Financing Activities

    

Issuance of debt

     -        485   

Repayment of debt

     (946     (1,668)   

Special cash distribution from Phillips 66

     -       7,818   

Change in restricted cash

     748       (2,468)   

Issuance of company common stock

     12       83   

Repurchase of company common stock

     -       (5,098)   

Dividends paid

     (2,481     (2,469)   

Other

     (593     (547)   

 

 

Net cash used in continuing financing activities

     (3,260     (3,864)   

Net cash used in discontinued operations

     -       (2,019)   

 

 

Net Cash Used in Financing Activities

     (3,260     (5,883)   

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

     (85     17   

 

 

Net Change in Cash and Cash Equivalents

     265       (4,512)   

Cash and cash equivalents at beginning of period

     3,618       5,780   

 

 

Cash and Cash Equivalents at End of Period

   $ 3,883       1,268   

 

 

See Notes to Consolidated Financial Statements.

 

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Notes to Consolidated Financial Statements    ConocoPhillips 

Note 1—Basis of Presentation

The interim-period financial information presented in the financial statements included in this report is unaudited and, in the opinion of management, includes all known accruals and adjustments necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature unless otherwise disclosed. Certain notes and other information have been condensed or omitted from the interim financial statements included in this report. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and notes included in our 2012 Annual Report on Form 10-K.

As a result of our separation of Phillips 66 on April 30, 2012, the results of operations for our former refining, marketing and transportation businesses; most of our former Midstream segment; our former Chemicals segment; and our power generation and certain technology operations included in our former Emerging Businesses segment (collectively, our “Downstream business”), have been classified as discontinued operations for all periods presented. In addition, the results of operations for our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Algerian and Nigerian businesses have been classified as discontinued operations for all periods presented. See Note 3—Discontinued Operations, for additional information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

Note 2—Change in Accounting Principles

Effective January 1, 2013, we early adopted, on a prospective basis, Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment (CTA) upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity.” This ASU clarifies that the CTA should not be released into net income unless a parent sells a part of its investment within a foreign entity which represents the complete or substantially complete liquidation of the reporting parent’s investment in the broader foreign entity. The ASU also requires the release of all the related CTA into net income upon gaining control in a step acquisition of an equity method investment that is considered to be a standalone foreign entity, and a pro rata release of the related CTA into net income upon a partial sale of an interest in an equity method investment that is considered to be a standalone foreign entity. There was no impact to our consolidated financial statements from the early adoption of this standard.

Note 3—Discontinued Operations

Separation of Downstream Business

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution. The principal funds from the special cash distribution were designated solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. The cash was included in the “Restricted cash” line on our consolidated balance sheet. No balance remained from the cash distribution as of September 30, 2013. We also entered into several agreements with Phillips 66 in order to effect the separation and govern our relationship with Phillips 66.

 

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Table of Contents

Sales and other operating revenues and income from discontinued operations related to Phillips 66 for the three- and nine-month periods ended September 30, 2012, were as follows:

 

     Millions of Dollars  
     2012  
     Three Months Ended      Nine Months Ended  
     September 30      September 30  
  

 

 

 

Sales and other operating revenues from discontinued operations

   $ 2        62,109   

 

 

Income from discontinued operations before-tax

   $ 2        1,792   

Income tax expense

     -        542   

 

 

Income from discontinued operations

   $ 2        1,250   

 

 

Income from discontinued operations after-tax includes transaction, information systems and other costs incurred to effect the separation of $70 million for the nine-month period ended September 30, 2012. No separation costs were incurred during the first nine months of 2013.

Prior to the separation, commodity sales to and purchases from Phillips 66 were $4,973 million and $166 million, respectively, for the nine-month period ended September 30, 2012. Prior to May 1, 2012, commodity sales and related costs were eliminated in consolidation between ConocoPhillips and Phillips 66. Beginning May 1, 2012, these revenues and costs represent third-party transactions with Phillips 66.

Other Discontinued Operations

As part of our ongoing asset disposition program, we agreed to sell our interest in Kashagan and our Algerian and Nigerian businesses (collectively, the “Disposition Group”). The Disposition Group was previously part of the Other International operating segment.

On November 26, 2012, we notified government authorities in Kazakhstan and co-venturers of our intent to sell the Company’s 8.4 percent interest in Kashagan to ONGC Videsh Limited (OVL). On July 2, 2013, we received notification from the government of Kazakhstan indicating it is exercising its right to pre-empt the proposed sale to OVL and designating KazMunayGas (KMG) as the entity to acquire the interest. On October 31, 2013, we completed the transaction with KMG for total proceeds of $5.4 billion. We recorded pre-tax impairments of $606 million and $43 million in the fourth quarter of 2012 and the first quarter of 2013, respectively. At September 30, 2013, the carrying value of the net assets related to our interest in Kashagan was $5.3 billion, net of impairments.

On December 18, 2012, we entered into an agreement with Pertamina to sell our wholly owned subsidiary, ConocoPhillips Algeria Ltd., for a total of $1.75 billion plus customary adjustments. The transaction is targeted to close by the end of 2013. We received a deposit of $175 million in December 2012. The deposit is refundable in the event our co-venturer exercises its preemptive rights, which have been waived, or government approval is not received. At September 30, 2013, the net carrying value of our Algerian assets was $714 million.

On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigerian business unit. This included its upstream affiliates and Phillips (Brass) Limited, which owns a 17 percent interest in the Brass LNG Project. Brass LNG plans to construct an LNG facility in the Niger Delta. In September 2013, we agreed to extend the outside date, or the date the sales agreements may terminate, for our Nigerian upstream affiliates to November 30, 2013, in order to provide additional time for Oando to obtain financing. This sale is expected to generate proceeds of $1.65 billion plus customary adjustments. We received a deposit of $435 million in December 2012 and may retain the deposit if closing does not occur due to default by the buyer or failure to obtain all consents required under Nigerian petroleum laws. In September 2013, we also agreed to extend the date for closing the sale of our interest in Brass LNG to the first quarter of 2014, subject to certain conditions. The sale of Brass LNG would generate proceeds of $105 million plus customary adjustments. At September 30, 2013, the net carrying value of our Nigerian assets was $371 million.

 

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At September 30, 2013, each component of the Disposition Group met the criteria to be classified as held for sale. Accordingly, we classified $11 million of loans and advances to related parties in the “Accounts and notes receivable—related parties” line and $7,421 million of noncurrent assets in the “Prepaid expenses and other current assets” line of our consolidated balance sheet. In addition, we classified $905 million of noncurrent liabilities in the “Accrued income and other taxes” line and $136 million of asset retirement obligations in the “Other accruals” line of our consolidated balance sheet. The carrying amounts of the major classes of assets and liabilities associated with the Disposition Group were as follows:

 

     Millions of Dollars  
         September 30      December 31  
     2013      2012  
  

 

 

 

Assets

     

Accounts and notes receivable

   $ 364        268   

Accounts and notes receivable—related parties

     1         

Inventories

     56        44   

Prepaid expenses and other current assets

     103        220   

 

 

Total current assets of discontinued operations

     524        533   

Investments and long-term receivables

     300        272   

Loans and advances—related parties

     11        29   

Net properties, plants and equipment

     7,119        6,629   

Other assets

     2         

 

 

Total assets of discontinued operations

   $ 7,956        7,467   

 

 

 

Liabilities

     

Accounts payable

   $ 432        471   

Accrued income and other taxes

     70        125   

 

 

Total current liabilities of discontinued operations

     502        596   

Asset retirement obligations and accrued environmental costs

     136        131   

Deferred income taxes

     905        759   

 

 

Total liabilities of discontinued operations

   $ 1,543        1,486   

 

 

Sales and other operating revenues and income from discontinued operations related to the Disposition Group were as follows:

 

     Millions of Dollars  
         Three Months Ended    
September 30
         Nine Months Ended    
September 30
 
     2013      2012           2013      2012   
  

 

 

    

 

 

 

Sales and other operating revenues from discontinued operations

   $ 353        380         892        1,095   

 

 

 

Income from discontinued operations before-tax

   $ 193        165         398        511   

Income tax expense

     136        94         215        343   

 

 

Income from discontinued operations

   $ 57        71         183        168   

 

 

 

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Note 4—Variable Interest Entities (VIEs)

We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on our significant VIEs follows:

Freeport LNG Development, L.P. (Freeport LNG)

We have an agreement with Freeport LNG to participate in an LNG receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity, which expires in 2033. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. At September 30, 2013, the prepaid balance of the terminal use agreement was $269 million, which is primarily reflected in the “Other assets” line on our consolidated balance sheet. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $522 million at September 30, 2013, and $565 million at December 31, 2012.

In July 2013, we reached an agreement with Freeport LNG to terminate our long-term agreement at the Freeport LNG Terminal, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. Upon satisfaction of these conditions, currently expected to occur by the end of the first quarter of 2014, we will pay Freeport LNG a termination fee of approximately $600 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport to partially fund the original construction of the terminal. When the agreement becomes effective, we expect to recognize an after-tax charge to earnings of approximately $540 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero.

Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of Freeport LNG do not have any substantive decision making ability. Since we do not have the unilateral power to direct the key activities which most significantly impact its economic performance, we are not the primary beneficiary of Freeport LNG. These key activities primarily involve or relate to operating and maintaining the terminal. We also performed an analysis of the expected losses and determined we are not the primary beneficiary. This expected loss analysis took into account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial insurance to mitigate any loan losses. The loan to Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity investment.

Australia Pacific LNG (APLNG)

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary of APLNG because we share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the key activities of APLNG that most significantly impact its economic performance, which involve activities related to the production and commercialization of coalbed methane, as well as LNG processing and export marketing. As a result, we do not consolidate APLNG, and it is accounted for as an equity method investment.

As of September 30, 2013, we have not provided any financial support to APLNG other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 7—Investments, Loans and Long-Term Receivables, and Note 13—Guarantees, for additional information.

 

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Note 5—Inventories

Inventories consisted of the following:

 

     Millions of Dollars  
     September 30
2013
     December 31
2012
 
  

 

 

 

Crude oil and petroleum products

   $ 506        244  

Materials, supplies and other

     762        721  

 

 
   $ 1,268        965  

 

 

Inventories valued on the last-in, first-out (LIFO) basis totaled $374 million and $147 million at September 30, 2013, and December 31, 2012, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $140 million at September 30, 2013, and $200 million at December 31, 2012.

Note 6—Assets Held for Sale or Sold

Our interest in Kashagan and the Algerian and Nigerian business units were considered held for sale at September 30, 2013. These assets are classified as discontinued operations. See Note 3—Discontinued Operations, for additional information.

In March 2013, we sold the majority of our properties in the Cedar Creek Anticline for $989 million and recognized a before-tax loss on disposition of $49 million, which was included in the “Gain on dispositions” line on our consolidated income statement for the nine-month period ended September 30, 2013. At the time of the disposition, the carrying value of our interest, which was included in the Lower 48 and Latin America segment, was $1,038 million, which included $1,066 million of properties, plants and equipment (PP&E) and $28 million of asset retirement obligations.

In June 2013, we sold a portion of our working interests in the Browse and Canning basins for $402 million. Because we retained a working interest in the unproved properties, proceeds were treated as a reduction of the carrying value of PP&E with no gain or loss on disposition recognized. Prior to the partial disposition, the carrying value of the PP&E associated with our interests, included in our Asia Pacific and Middle East segment, was $486 million.

In August 2013, we sold our interest in the Clyden undeveloped oil sands leasehold for $724 million and recognized a before-tax gain on disposition of $614 million, which was included in the “Gain on dispositions” line on our consolidated income statement for the three- and nine-month periods ended September 30, 2013. At the time of the disposition, the carrying value of our interest in Clyden, which was included in the Canada segment, was $110 million and was classified as PP&E.

In August 2013, we also sold our 39 percent interest in Phoenix Park Gas Processors Limited for $593 million and recognized a before-tax gain on disposition of $417 million, which was included in the “Gain on dispositions” line on our consolidated income statement for the three- and nine-month periods ended September 30, 2013. At the time of the disposition, the carrying value of our equity investment in Phoenix Park, which was included in our Lower 48 and Latin America segment, was $176 million.

 

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Note 7—Investments, Loans and Long-Term Receivables

APLNG

In the fourth quarter of 2012, APLNG satisfied all conditions precedent to drawdown from the $8.5 billion project finance facility. The facility consists of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $2.9 billion, the Export-Import Bank of China for approximately $2.7 billion, and a syndicate of Australian and international commercial banks for approximately $2.9 billion. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility until the project achieves financial completion. See Note 13—Guarantees, for additional information.

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 4—Variable Interest Entities (VIEs), for additional information.

At September 30, 2013, the book value of our equity method investment in APLNG was $10,526 million, which included $1,601 million of cumulative translation effects due to strengthening of the Australian dollar relative to the U.S. dollar over time, and is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

Loans and Long-Term Receivables

As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans made to certain affiliated and non-affiliated companies. Significant loans to affiliated companies at September 30, 2013, included the following:

 

    $522 million in loan financing to Freeport LNG. See Note 4—Variable Interest Entities (VIEs), for additional information.
    $1,005 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3).

The long-term portion of these loans is included in the “Loans and advances—related parties” line on our consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”

Note 8—Suspended Wells

The capitalized cost of suspended wells at September 30, 2013, was $1,066 million, an increase of $28 million from $1,038 million at year-end 2012. No suspended wells were charged to dry hole expense during the first nine months of 2013 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2012.

 

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Note 9—Impairments

During the three- and nine-month periods ended September 30, 2013 and 2012, we recognized before-tax impairment charges within the following segments:

 

     Millions of Dollars  
         Three Months Ended    
September 30
         Nine Months Ended    
September 30
 
     2013      2012       2013      2012   
  

 

 

    

 

 

 

Canada

   $ -                 -         213   

Europe

     -                28        79   

Asia Pacific and Middle East

     1                3         

 

 
   $ 1                31        296   

 

 

The nine-month periods of 2013 and 2012 included impairments in our Europe segment of $28 million and $79 million, respectively, primarily due to increases in the asset retirement obligation for the U.K. Don Field, which has ceased production. Additionally, the nine-month period of 2012 included a $213 million property impairment in our Canada segment for the carrying value of capitalized project development costs associated with our Mackenzie Gas Project. Advancement of the project was suspended indefinitely in the first quarter of 2012 due to a continued decline in market conditions and the lack of acceptable commercial terms. We also recorded a $481 million impairment for the undeveloped leasehold costs associated with the project, which was included in the “Exploration expenses” line on our consolidated income statement.

Note 10—Debt

We have two commercial paper programs supported by our $7.5 billion revolving credit facility: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.15 billion program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At September 30, 2013, and December 31, 2012, we had no direct outstanding borrowings or letters of credit issued under our revolving credit facilities. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, there was $961 million of commercial paper outstanding at September 30, 2013, compared with $1,055 million at December 31, 2012. Since we had $961 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.5 billion in borrowing capacity under our revolving credit facilities at September 30, 2013.

At September 30, 2013, we classified $865 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.

During the first nine months of 2013, we repaid the following debt instruments at maturity:

 

    The $100 million 7.625% Debentures due 2013.
    The $750 million 5.50% Notes due 2013.

During the second quarter of 2013, a lease of a semi-submersible floating production system (FPS) commenced for the Gumusut development, located in Malaysia, in which we are a co-venturer. The FPS lease provides for an initial noncancelable term of 15 years, a subsequent 5-year cancelable term with no required lease payments, and an additional 5-year term with terms and conditions to be agreed at a later date. The lease has no ongoing purchase options or escalation clauses. Certain contingent rental payments may be incurred if actual commissioning costs exceed provisioned amounts. The lease does not impose any significant restrictions concerning dividends, debt or further leasing activities.

 

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A capital lease asset and a capital lease obligation of $906 million were recognized for our proportionate interest in the FPS. The value of the capital lease asset and associated obligation are based on the present value of the future minimum lease payments using our pre-tax incremental borrowing rate of 3.58 percent for debt with similar terms. Following the startup of the FPS, the capital lease asset will be depreciated over a period consistent with the estimated proved reserves of Gumusut using the unit-of-production method with the associated depreciation included in the “Depreciation, depletion and amortization” line on our consolidated income statement. Future minimum lease payments under the capital lease are $46 million for the remainder of 2013, $78 million per year for 2014 through 2017, and $814 million for all years thereafter.

Note 11—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL Partnership. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, approximately $803 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2013, consolidated balance sheet. The principal portion of these payments, which totaled $575 million in the first nine months of 2013, is included in the “Other” line in the financing activities section on our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

Note 12—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first nine months of 2013 and 2012 was as follows:

 

     Millions of Dollars  
     2013      2012  
     Common
Stockholders’
Equity
    

Non-

Controlling
Interest

     Total
Equity
     Common
Stockholders’
Equity
    

Non-

Controlling
Interest

     Total
Equity
 
  

 

 

    

 

 

 

Balance at January 1

   $ 47,987         440         48,427         65,239         510         65,749   

Net income

     6,669         43         6,712         7,002         55         7,057   

Dividends

     (2,481)                 (2,481)         (2,469)                 (2,469)   

Repurchase of company common stock

                             (5,098)                 (5,098)   

Distributions to noncontrolling interests

             (59)         (59)         -          (63)         (63)   

Separation of Downstream business

                             (18,623)         (31)         (18,654)   

Other changes, net*

     (1,062)                 (1,062)         1,355                 1,355   

 

 

Balance at September 30

   $ 51,113         424         51,537         47,406         471         47,877   

 

 

*Includes components of other comprehensive income, which are disclosed separately in our consolidated statement of comprehensive income.

 

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Note 13—Guarantees

At September 30, 2013, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At September 30, 2013, we have outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing September 2013 exchange rates:

 

    We have guaranteed APLNG’s performance with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1 and Train 2 Notices to Proceed. We estimate the remaining term of this guarantee is four years. Our maximum potential amount of future payments related to this guarantee is approximately $150 million and would become payable if APLNG cancels the applicable construction contract and does not perform with respect to the amounts owed to the contractor.

 

    We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. Our maximum potential amount of future payments under the guarantee is estimated to be $3.2 billion, which could be payable if the full debt financing capacity is utilized and completion of the project is not achieved. Our guarantee of the project financing will be released upon meeting certain completion tests with milestones, which we estimate would occur beginning in 2016. Our maximum exposure at September 30, 2013, is $2.5 billion based upon our pro-rata share of the facility used at that date. At September 30, 2013, the carrying value of this guarantee is approximately $114 million.

 

    In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to guarantee an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 3 to 18 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1.0 billion ($2.1 billion in the event of intentional or reckless breach), and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.

 

    We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of up to 32 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $200 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $270 million, which consist primarily of guarantees of the residual value of leased corporate aircraft, guarantees to fund the short-term cash liquidity deficit of two joint ventures, a guarantee for our portion of a joint venture’s debt obligations and a guarantee of minimum charter revenue for an LNG vessel. These guarantees have remaining terms of up to 11 years or the life of the venture and would become payable if, upon sale, certain asset values are lower than guaranteed amounts, business conditions decline at guaranteed entities, or as a result of non-performance of contractual terms by guaranteed parties.

 

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Indemnifications

Over the years, we have entered into various lease agreements or agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these leases and sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at September 30, 2013, was approximately $60 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount at September 30, 2013, were approximately $50 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 14—Contingencies and Commitments.

In connection with the separation of the Downstream business, the Company entered into an Indemnification and Release Agreement with Phillips 66. This agreement provided for cross-indemnities between Phillips 66 and ConocoPhillips and established procedures for handling claims subject to indemnification and related matters. We evaluated the impact of the indemnifications given and the Phillips 66 indemnifications received as of the separation date and concluded those fair values were immaterial.

Note 14—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been made against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With respect to income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental

We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on

 

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currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar and time limits.

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except in respect of sites acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At September 30, 2013, our balance sheet included a total environmental accrual of $355 million, compared with $364 million at December 31, 2012, for remediation activities in the U.S. and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

Legal Proceedings

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, are required.

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at September 30, 2013, we had performance obligations secured by letters of credit of $809 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.

In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on

 

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November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. An additional arbitration phase is now proceeding to determine the amount of damages owed to ConocoPhillips for Venezuela’s actions.

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by the ICSID tribunal, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. On April 24, 2012, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on December 14, 2012, in favor of Burlington, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase is now proceeding to determine the damages owed to ConocoPhillips for Ecuador’s actions.

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax assessments. Between December 2010 and September 2013, ConocoPhillips paid, under protest, tax assessments totaling approximately $232 million, which are primarily recorded in the “Investments and long-term receivables” line on our consolidated balance sheet. The arbitration will be conducted in Singapore under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste government. The arbitration process is currently underway. Future impacts on our business are not known at this time.

Note 15—Derivative and Financial Instruments

Derivative Instruments

We use futures, forwards, swaps and options in various markets to meet our customer needs and capture market opportunities. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids. Under our current business model, we are not required to register as a Swap Dealer or Major Swap Participant.

Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented net. Related cash flows are recorded as operating activities on the consolidated statement of cash flows. On our consolidated income statement, realized and unrealized gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the normal purchase normal sale exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use hedge accounting for our commodity derivatives.

 

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The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:

 

     Millions of Dollars  
     September 30      December 31  
     2013      2012  
  

 

 

 

Assets

     

Prepaid expenses and other current assets

   $ 871        1,538   

Other assets

     74        105   

Liabilities

     

Other accruals

     882        1,509   

Other liabilities and deferred credits

     71        99   

 

 

The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income statement were:

 

     Millions of Dollars  
     Three Months Ended
September 30
     Nine Months Ended
September 30
 
  

 

 

    

 

 

 
     2013     2012       2013      2012  
  

 

 

    

 

 

 

    

          

Sales and other operating revenues

   $ 61       (217)         (122)         (357)   

Other income

     -                     (2)   

Purchased commodities

     (68     184         103         288   

 

 

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts.

 

     Open Position
Long/(Short)
 
     September 30     December 31  
     2013     2012  
  

 

 

 

    

    

Natural gas and power (billions of cubic feet equivalent)

    

Fixed price

     (29     (48)   

Basis

     (11     125   

 

 

Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily consists of transactions designed to mitigate our cash-related and foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates. We do not elect hedge accounting on our foreign currency exchange derivatives.

 

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The following table presents the gross fair values of our foreign currency exchange derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:

 

     Millions of Dollars  
         September 30      December 31   
     2013      2012   
  

 

 

 

Assets

     

Prepaid expenses and other current assets

   $ 12        32   

Liabilities

     

Other accruals

     1         

Other liabilities and deferred credits

     -         

 

 

The (gains) losses from foreign currency exchange derivatives incurred, and the line item where they appear on our consolidated income statement were:

 

     Millions of Dollars  
         Three Months Ended    
September 30
     Nine Months Ended
September 30
 
     2013       2012         2013        2012   
  

 

 

    

 

 

 

Foreign currency transaction (gains) losses

   $ (57     (39)         -        (129)   

 

 

We had the following net notional position of outstanding foreign currency exchange derivatives:

 

     In Millions  
     Notional Currency  
          September 30      December 31   
          2013      2012   
  

 

 

Sell U.S. dollar, buy other currencies*

   USD      1,133        2,573   

Buy U.S. dollar, sell other currencies**

   USD      -         140   

Buy British pound, sell euro

   GBP      15          

Buy euro, sell British pound

   EUR      -         96   

 

 
  *Primarily Norwegian krone, British pound and Canadian dollar.
**Primarily euro, Canadian dollar and Norwegian krone.

Financial Instruments

We have certain financial instruments on our consolidated balance sheet related to interest bearing time deposits and commercial paper. The following held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet:

 

     Millions of Dollars  
         September 30
2013
     December 31 
2012 
 
  

 

 

 

Cash

   $ 759        829   

Time Deposits

     3,124        2,789   

 

 
   $ 3,883        3,618   

 

 

 

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In conjunction with the separation of our Downstream business, we received a special cash distribution from Phillips 66. See Note 3—Discontinued Operations, for additional information. The balance of the special cash distribution was zero at September 30, 2013, and $748 million at December 31, 2012, and was included in “Restricted cash” on our consolidated balance sheet. At December 31, 2012, the funds in the restricted cash account were invested in money market funds with maturities within 90 days from December 31, 2012.

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, over-the-counter (OTC) derivative contracts and trade receivables. Our cash equivalents are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.

The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral, such as certain transactions administered through the New York Mercantile Exchange or the IntercontinentalExchange.

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on September 30, 2013, and December 31, 2012, was $83 million and $130 million, respectively. For these instruments, no collateral was posted as of September 30, 2013, or December 31, 2012. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on September 30, 2013, we would be required to post no additional collateral to our counterparties. If we had been downgraded below investment grade, we would be required to post $83 million of additional collateral, either with cash or letters of credit.

 

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Note 16—Fair Value Measurement

We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:

 

    Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.
    Level 2: Inputs other than quoted prices which are directly or indirectly observable.
    Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no material transfers in or out of Level 1.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives and certain investments to support nonqualified deferred compensation plans. The deferred compensation investments are measured at fair value using unadjusted prices available from national securities exchanges; therefore, these assets are categorized as Level 1 in the fair value hierarchy. Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts that are long term in nature and where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was not material.

The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):

 

     Millions of Dollars  
     September 30, 2013      December 31, 2012  
     Level 1      Level 2      Level 3      Total      Level 1      Level 2      Level 3      Total  
  

 

 

    

 

 

 

Assets

                       

Deferred compensation investments

   $ 297                       297         305                       305   

Commodity derivatives

     718         213         11         942         1,052         567         18         1,637   

 

 

Total assets

   $     1,015         213         11         1,239           1,357         567         18         1,942   

 

 

Liabilities

                       

Commodity derivatives

   $ 724         218                950         1,031         567                1,602   

 

 

Total liabilities

   $ 724         218                950         1,031         567                1,602   

 

 

 

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The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet:

 

     Millions of Dollars  
     Gross      Gross        Net Amounts               Net Amounts  
   Amounts          Amounts      Excluding      Cash      Subject  
   Recognized      Offset      Collateral            Collateral      to Setoff  
  

 

 

 

September 30, 2013

              

Assets

   $ 928         815         113         11         102   

Liabilities

     941         815         126         21         105   

 

 

December 31, 2012

              

Assets

   $             1,621         1,403         218         29         189   

Liabilities

     1,588         1,403         185         16         169   

 

 

At September 30, 2013, and December 31, 2012, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Reported Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:

 

    Cash and cash equivalents and restricted cash: The carrying amount reported on the balance sheet approximates fair value.
    Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of fixed-rate related party loans is consistent with Loans and advances—related parties.
    Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 7—Investments, Loans and Long-Term Receivables, for additional information.
    Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of the joint venture acquisition obligation is consistent with the methodology below.
    Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.
    Joint venture acquisition obligation—related party: Fair value is estimated based on the net present value of the future cash flows as a Level 2 fair value. At September 30, 2013, and December 31, 2012, effective yield rates were 0.74 percent and 0.7 percent, respectively, based on yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread and the amortizing nature of the obligation principal. See Note 11—Joint Venture Acquisition Obligation, for additional information.

 

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The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):

 

     Millions of Dollars  
     Carrying Amount      Fair Value  
     September 30      December 31      September 30      December 31  
     2013      2012      2013      2012  
  

 

 

    

 

 

 

Financial assets

           

Deferred compensation investments

   $ 297         305         297         305   

Commodity derivatives

     119         221         119         221   

Total loans and advances—related parties

     1,545         1,697         1,707         1,916   

Financial liabilities

           

Total debt, excluding capital leases

     20,746         21,709         23,642         26,349   

Total joint venture acquisition obligation

     3,006         3,582         3,274         3,968   

Commodity derivatives

     117         199         117         199   

 

 

Note 17—Accumulated Other Comprehensive Income

Accumulated other comprehensive income in the equity section of our consolidated balance sheet included:

 

     Millions of Dollars  
     Defined
Benefit Plans
    Foreign
Currency
Translation
    Accumulated
Other
Comprehensive
Income (Loss)
 
  

 

 

 

December 31, 2012

   $ (1,425     5,512       4,087  

Other comprehensive income (loss)

     322       (1,697     (1,375

 

 

September 30, 2013

   $ (1,103     3,815       2,712  

 

 

The following table summarizes reclassifications out of accumulated other comprehensive income during the three- and nine-month periods ended September 30, 2013:

 

     Millions of Dollars  
     2013  
     Three Months Ended
September 30
    

Nine Months

Ended
September 30

 
  

 

 

 

    

     

Defined Benefit Plans

   $ 65        133  

 

 

Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $40 million and $83 million for the three- and nine-month periods ended September 30, 2013, respectively. See Note 19—Employee Benefit Plans, for additional information.

There were no items within accumulated other comprehensive income related to noncontrolling interests.

 

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Note 18—Cash Flow Information

 

     Millions of Dollars  
         Nine Months Ended
September 30
 
         2013       2012   
  

 

 

 

Cash Payments

     

Interest

   $ 448         596   

Income taxes

     4,050         6,010   

 

 

Net Sales (Purchases) of Short-Term Investments

     

Short-term investments purchased

   $ (97)         (497)   

Short-term investments sold

     98         1,094   

 

 
   $        597   

 

 

During the second quarter of 2013, we recognized a capital lease asset, a non-cash investing activity, and incurred a capital lease obligation, a non-cash financing activity, for $906 million. For more information about this capital lease obligation, see Note 10—Debt.

Note 19—Employee Benefit Plans

Pension and Postretirement Plans

 

     Millions of Dollars  
     Pension Benefits      Other Benefits    
     2013      2012      2013      2012   
  

 

 

    

 

 

    

 

 

    

 

 

 
         U.S.      Int’l.      U.S.      Int’l.                

Components of Net Periodic Benefit Cost

                 

Three Months Ended September 30

                 

Service cost

   $ 35         25         33         20                  

Interest cost

     35         35         39         35                 

Expected return on plan assets

     (47)         (40)         (47)         (37)                   

Amortization of prior service cost (credit)

            (2)                (2)         (1)         (1)   

Recognized net actuarial loss

     38         18         41         13                   

Settlements

     50                 137                           

 

 

Net periodic benefit cost

   $ 113         36         204         29                  

 

 

Nine Months Ended September 30

                 

Service cost

   $ 104         76         133         70                 

Interest cost

     107         108         150         116         20         26   

Expected return on plan assets

     (140)         (120)         (177)         (120)                   

Amortization of prior service cost (credit)

            (6)                (6)         (3)         (3)   

Recognized net actuarial loss (gain)

     113         55         145         46                (1)   

Settlements

     50                 137                           

 

 

Net periodic benefit cost

   $ 239         113         393         106         21         27   

 

 

In connection with the separation of the Downstream business on April 30, 2012, ConocoPhillips entered into an Employee Matters Agreement with Phillips 66 which provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by ConocoPhillips upon separation. As such, changes in net periodic benefit cost included in the table above primarily relate to the employees of Phillips 66 no longer participating in the ConocoPhillips benefit plans for the nine-month period ended September 30, 2013.

 

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During the first nine months of 2013, we contributed $231 million to our domestic benefit plans and $155 million to our international benefit plans.

During the three months ended September 30, 2013, we concluded that lump-sum benefit payments will exceed the sum of service and interest costs for the plan year for the U.S. qualified pension plan. As a result, we recognized a proportionate share of prior actuarial losses, or pension settlement expense, of $50 million. In conjunction with the recognition of pension settlement expense, the assets and pension benefit obligation of the qualified pension plan were remeasured. At the measurement date, the net pension liability decreased $301 million to $725 million, resulting in a corresponding increase to other comprehensive income.

During the three months ended September 30, 2012, we concluded that lump-sum benefit payments would exceed the sum of service and interest costs for the plan year for the U.S. qualified pension plan and U.S. non-qualified supplemental retirement plan. As a result, we recognized a proportionate share of prior actuarial losses, or pension settlement expense, of $137 million. In conjunction with the recognition of pension settlement expense, the assets and pension benefit obligation of the qualified pension plan were remeasured. At the measurement date, the net pension liability increased $432 million to $1,283 million, resulting in a corresponding decrease to other comprehensive income.

Note 20—Related Party Transactions

We consider our equity method investments to be related parties. Significant transactions with related parties were:

 

     Millions of Dollars  
       Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2013      2012       2013      2012   
  

 

 

    

 

 

 

Operating revenues and other income

   $ 35               74        42   

Purchases*

     48        92         138        228   

Operating expenses and selling, general and administrative expenses

     52        52         141        133   

Net interest expense**

     6               22        30   

 

 

  *2012 has been restated to include certain related party transactions.

**We paid interest to, or received interest from, various affiliates, including FCCL Partnership. See Note 7—Investments, Loans and Long-

Term Receivables and Note 11—Joint Venture Acquisition Obligation, for additional information on loans to affiliated companies.

Note 21—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. We manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International.

On April 30, 2012, our Downstream business was separated into a stand-alone, publicly traded corporation, Phillips 66. In 2012, we also agreed to sell our Nigerian and Algerian businesses and our interest in Kashagan. Accordingly, results for these operations have been reported as discontinued operations in all periods presented. Commodity sales to Phillips 66, which were previously eliminated in consolidation prior to the separation, are now reported as third-party sales. For additional information, see Note 3—Discontinued Operations.

 

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Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, costs associated with the separation and certain technology activities, net of licensing revenues. Corporate assets include all cash and cash equivalents and restricted cash.

We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

Analysis of Results by Operating Segment

     Millions of Dollars  
       Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2013     2012       2013     2012   
  

 

 

    

 

 

 

Sales and Other Operating Revenues

         

Alaska

   $ 2,102       2,005         6,375       7,135   

 

 

Lower 48 and Latin America

     4,938       4,807         14,661       14,110   

Intersegment eliminations

     (24     (40)         (79     (196)   

 

 

Lower 48 and Latin America

     4,914       4,767         14,582       13,914   

 

 

Canada

     1,264       1,288         3,924       3,580   

Intersegment eliminations

     (135     (117)         (448     (330)   

 

 

Canada

     1,129       1,171         3,476       3,250   

 

 

Europe

     3,024       3,285         8,885       10,813   

Intersegment eliminations

     -                -        (72)   

 

 

Europe

     3,024       3,285         8,885       10,741   

 

 

Asia Pacific and Middle East

     2,196       2,167         6,500       5,697   

Intersegment eliminations

     -        (41)         -        (41)   

 

 

Asia Pacific and Middle East

     2,196       2,126         6,500       5,656   

 

 

Other International

     262       686         1,202       1,569   

Corporate and Other

     16       101         139       133   

 

 

Consolidated sales and other operating revenues

   $ 13,643       14,141         41,159       42,398   

 

 

Net Income Attributable to ConocoPhillips

         

Alaska

   $ 494       535         1,719       1,706   

Lower 48 and Latin America

     498       182         878       556   

Canada

     642       (31)         780       (674)   

Europe

     284       132         976       1,190   

Asia Pacific and Middle East

     741       669         2,676       3,179   

Other International

     (2     492         26       456   

Corporate and Other

     (234     (254)         (569     (827)   

Discontinued operations

     57       73         183       1,416   

 

 

Consolidated net income attributable to ConocoPhillips

   $ 2,480       1,798         6,669       7,002   

 

 

 

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Table of Contents
     Millions of Dollars  
       September 30
2013
     December 31
2012
 
  

 

 

 

Total Assets

     

Alaska

   $ 11,587        10,950   

Lower 48 and Latin America

     29,018        28,895   

Canada

     22,794        22,308   

Europe

     16,275        15,562   

Asia Pacific and Middle East

     24,695        23,721   

Other International

     1,515        1,418   

Corporate and Other

     5,920        6,823   

Discontinued operations

     7,956        7,467   

 

 

Consolidated total assets

   $ 119,760        117,144   

 

 

Note 22—Income Taxes

Our effective tax rates from continuing operations were 45 percent for both the third quarter and first nine months of 2013, compared with 52 percent for the corresponding periods of 2012. The lower rates were primarily due to a smaller proportion of income in higher tax jurisdictions in 2013, as well as tax expense recognized in the third quarter of 2012 associated with a change in U.K. tax legislation. Additionally, the tax rate for the first nine months of 2013 reflected a favorable tax resolution associated with the sale of certain western Canada properties, which occurred in a prior year.

During the first nine months of 2013, unrecognized tax benefits decreased $220 million to $652 million at September 30, 2013, mainly due to the favorable tax resolution noted above. Included in this balance is $419 million which, if recognized, would impact our effective tax rate.

For both the third quarter and the first nine months of 2013, the effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

 

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Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, 100 percent owned subsidiaries of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:

 

    ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
    All other nonguarantor subsidiaries of ConocoPhillips.
    The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.

Subsequent to September 30, 2013, we completed a legal amalgamation of ConocoPhillips Canada Funding Company I, ConocoPhillips Canada Funding Company II and Burlington Resources Finance Company, with the amalgamated company continuing as ConocoPhillips Canada Funding Company I. The amalgamation did not significantly change the nature of the outstanding debt of these entities or the terms of parental guarantees, which remain full and unconditional, as well as joint and several. We do not expect the amalgamation to impact our consolidated financial position, results of operations or cash flows.

 

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Table of Contents
    Millions of Dollars  
   

 

Three Months Ended September 30, 2013

 
Income Statement     ConocoPhillips     ConocoPhillips
Company
    ConocoPhillips
Australia Funding
Company
    ConocoPhillips
Canada Funding
Company I
    ConocoPhillips
Canada Funding
Company II
    All Other
Subsidiaries
    Consolidating
Adjustments
    Total
Consolidated
 

Revenues and Other Income

               

Sales and other operating revenues

  $ -       4,625       -       -       -       9,018       -       13,643   

Equity in earnings of affiliates

    2,804       3,065       -       -       -       676       (5,836     709   

Gain on dispositions

    -       418       -       -       -       651       -       1,069   

Other income

    -       29       -       -       -       20       -       49   

Intercompany revenues

    21       27       -       22       8       1,864       (1,942      

 

 

Total Revenues and Other Income

    2,825       8,164       -       22       8       12,229       (7,778     15,470    

 

 

Costs and Expenses

               

Purchased commodities

    -       3,994       -       -       -       3,046       (1,332     5,708   

Production and operating expenses

    -       360       -       -       -       1,605       (3     1,962   

Selling, general and administrative expenses

    3       194       -       -       -       53       (1     249   

Exploration expenses

    -       157       -       -       -       156       -       313   

Depreciation, depletion and amortization

    -       245       -       -       -       1,657       -       1,902   

Impairments

    -       -       -       -       -       1       -        

Taxes other than income taxes

    -       55       -       -       -       609       -       664   

Accretion on discounted liabilities

    -       14       -       -       -       92       -       106   

Interest and debt expense

    618       85       -       19       8       27       (606     151   

Foreign currency transaction (gains) losses

    (15     (1     -       32       5       (12     -        

 

 

Total Costs and Expenses

    606       5,103       -       51       13       7,234       (1,942     11,065   

 

 

Income (loss) from continuing operations before income taxes

    2,219       3,061       -       (29     (5     4,995       (5,836     4,405   

Provision for income taxes

    (204     257       -       (1     1       1,913       -       1,966   

 

 

Income (Loss) From Continuing Operations

    2,423       2,804       -       (28     (6     3,082       (5,836     2,439   

Income from discontinued operations

    57       57       -       -       -       57       (114     57   

 

 

Net income (loss)

    2,480       2,861       -       (28     (6     3,139       (5,950     2,496   

Less: net income attributable to noncontrolling interests

    -       -       -       -       -       (16     -       (16)   

 

 

Net Income (Loss) Attributable to ConocoPhillips

  $ 2,480       2,861       -       (28     (6     3,123       (5,950     2,480   

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

  $ 3,352       3,733       -       (2     5       3,729       (7,465     3,352   

 

 
Income Statement   Three Months Ended September 30, 2012  

Revenues and Other Income

               

Sales and other operating revenues

  $ -       4,028       -       -       -       10,113       -       14,141   

Equity in earnings of affiliates

    2,098       2,485       -       -       -       332       (4,503     412   

Gain on dispositions

    -       3       -       -       -       115       -       118   

Other income (loss)

    (78     100       -       -       -       20       -       42   

Intercompany revenues

    21       94       11       22       8       751       (907      

 

 

Total Revenues and Other Income

    2,041       6,710       11       22       8       11,331       (5,410     14,713   

 

 

Costs and Expenses

               

Purchased commodities

    -       3,470       -       -       -       3,258       (371     6,357   

Production and operating expenses

    -       313       -       -       -       1,326       (2     1,637   

Selling, general and administrative expenses

    2       260       -       -       -       67       -       329   

Exploration expenses

    -       101       -       -       -       114       -       215   

Depreciation, depletion and amortization

    -       197       -       -       -       1,453       -       1,650   

Taxes other than income taxes

    -       57       -       -       -       616       -       673   

Accretion on discounted liabilities

    -       13       -       -       -       87       -       100   

Interest and debt expense

    542       76       10       19       8       40       (534     161   

Foreign currency transaction (gains) losses

    (28     (7     -       46       46       (57     -        

 

 

Total Costs and Expenses

    516       4,480       10       65       54       6,904       (907     11,122   

 

 

Income (loss) from continuing operations before income taxes

    1,525       2,230       1       (43     (46     4,427       (4,503     3,591   

Provision for income taxes

    (200     132       -       1       (6     1,924       -       1,851   

 

 

Income (Loss) From Continuing Operations

    1,725       2,098       1       (44     (40     2,503       (4,503     1,740   

Income from discontinued operations

    73       73       -       -       -       70       (143     73   

 

 

Net income (loss)

    1,798       2,171       1       (44     (40     2,573       (4,646     1,813   

Less: net income attributable to noncontrolling interests

    -       -       -       -       -       (15     -       (15)   

 

 

Net Income (Loss) Attributable to ConocoPhillips

  $ 1,798       2,171       1       (44     (40     2,558       (4,646     1,798   

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

  $ 2,260       2,633       1       7       (20     3,280       (5,901     2,260   

 

 

 

28


Table of Contents
    Millions of Dollars  
   

 

Nine Months Ended September 30, 2013

 
Income Statement     ConocoPhillips     ConocoPhillips
Company
    ConocoPhillips
Australia Funding
Company
    ConocoPhillips
Canada Funding
Company I
    ConocoPhillips
Canada Funding
Company II
    All Other
Subsidiaries
    Consolidating
Adjustments
    Total
Consolidated
 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Revenues and Other Income

               

Sales and other operating revenues

  $ -        13,710       -        -        -        27,449       -        41,159   

Equity in earnings of affiliates

    7,644       8,750       -        -        -        1,639       (16,468     1,565   

Gain on dispositions

    -        419       -        -        -        803       -        1,222   

Other income

    1       237       -        -        -        79       -        317   

Intercompany revenues

    62       108       13       66       25       5,258       (5,532       

 

 

Total Revenues and Other Income

    7,707       23,224       13       66       25       35,228       (22,000     44,263   

 

 

Costs and Expenses

               

Purchased commodities

    -        11,901       -        -        -        8,868       (3,706     17,063   

Production and operating expenses

    -        1,047       -        -        -        4,297       (23     5,321   

Selling, general and administrative expenses

    9       444       -        -        -        173       (19     607   

Exploration expenses

    -        491       -        -        -        420       -        911   

Depreciation, depletion and amortization

    -        674       -        -        -        4,867       -        5,541   

Impairments

    -        -        -        -        -        31       -        31   

Taxes other than income taxes

    -        180       -        -        -        2,018       -        2,198   

Accretion on discounted liabilities

    -        42       -        -        -        275       -        317   

Interest and debt expense

    1,809       245       12       58       24       56       (1,784     420   

Foreign currency transaction (gains) losses

    26       8       -        (38     (25     (5     -        (34)   

 

 

Total Costs and Expenses

    1,844       15,032       12       20       (1     21,000       (5,532     32,375   

 

 

Income from continuing operations before income taxes

    5,863       8,192       1       46       26       14,228       (16,468     11,888   

Provision for income taxes

    (623     548       -        1       2       5,431       -        5,359   

 

 

Income From Continuing Operations

    6,486       7,644       1       45       24       8,797       (16,468     6,529   

Income from discontinued operations

    183       183       -        -        -        183       (366     183   

 

 

Net income

    6,669       7,827       1       45       24       8,980       (16,834     6,712   

Less: net income attributable to noncontrolling interests

    -        -        -        -        -        (43     -        (43)   

 

 

Net Income Attributable to ConocoPhillips

  $ 6,669       7,827       1       45       24       8,937       (16,834     6,669   

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

  $ 5,294       6,452       1       (1     6       7,263       (13,721     5,294   

 

 
Income Statement   Nine Months Ended September 30, 2012  

Revenues and Other Income

               

Sales and other operating revenues

  $ -        12,598       -        -        -        29,800       -        42,398   

Equity in earnings of affiliates

    6,680       7,617       -        -        -        1,365       (14,231     1,431   

Gain on dispositions

    -        3       -        -        -        1,638       -        1,641   

Other income (loss)

    (77     155       -        -        -        90       -        168   

Intercompany revenues

    40       779       34       67       25       3,192       (4,137       

 

 

Total Revenues and Other Income

    6,643       21,152       34       67       25       36,085       (18,368     45,638   

 

 

Costs and Expenses

               

Purchased commodities

    -        11,044       -        -        -        9,484       (2,372     18,156   

Production and operating expenses

    -        917       -        -        -        4,102       (21     4,998   

Selling, general and administrative expenses

    10       690       -        -        -        199       (9     890   

Exploration expenses

    -        287       -        -        -        868       -        1,155   

Depreciation, depletion and amortization

    -        605       -        -        -        4,196       -        4,801   

Impairments

    -        -        -        -        -        296       -        296   

Taxes other than income taxes

    -        207       -        -        -        2,461       -        2,668   

Accretion on discounted liabilities

    -        39       -        -        -        269       -        308   

Interest and debt expense

    1,668       247       31       58       24       255       (1,735     548   

Foreign currency transaction (gains) losses

    (30     19       -        34       47       (53     -        17   

 

 

Total Costs and Expenses

    1,648       14,055       31       92       71       22,077       (4,137     33,837   

 

 

Income (loss) from continuing operations before income taxes

    4,995       7,097       3       (25     (46     14,008       (14,231     11,801   

Provision for income taxes

    (589     417       1       7       (6     6,332       -        6,162   

 

 

Income (Loss) From Continuing Operations

    5,584       6,680       2       (32     (40     7,676       (14,231     5,639   

Income from discontinued operations

    1,418       1,418       -        -        -        1,162       (2,580     1,418   

 

 

Net income (loss)

    7,002       8,098       2       (32     (40     8,838       (16,811     7,057   

Less: net income attributable to noncontrolling interests

    -        -        -        -        -        (55     -        (55)   

 

 

Net Income (Loss) Attributable to ConocoPhillips

  $ 7,002       8,098       2       (32     (40     8,783       (16,811     7,002   

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

  $ 7,881       8,968       2       24       (18     9,356       (18,332     7,881   

 

 

 

29


Table of Contents
    Millions of Dollars  
   

 

September 30, 2013

 
Balance Sheet     ConocoPhillips     ConocoPhillips
Company
    ConocoPhillips
Australia Funding
Company
    ConocoPhillips
Canada Funding
Company I
    ConocoPhillips
Canada Funding
Company II
    All Other
Subsidiaries
    Consolidating
Adjustments
    Total
Consolidated
 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Assets

               

Cash and cash equivalents

  $ -        190       -        54       2       3,637       -        3,883   

Accounts and notes receivable

    67       2,002       2       -        -        9,996       (3,662     8,405   

Inventories

    -        217       -        -        -        1,051       -        1,268   

Prepaid expenses and other current assets

    17       458       -        1       -        8,525       -        9,001   

 

 

Total Current Assets

    84       2,867       2       55       2       23,209       (3,662     22,557   

Investments, loans and long-term receivables*

    87,333       122,246       -        1,428       568       45,949       (232,358     25,166   

Net properties, plants and equipment

    -        9,082       -        -        -        62,047       -        71,129   

Other assets

    39       254       -        1       3       611       -        908   

 

 

Total Assets

  $ 87,456       134,449       2       1,484       573       131,816       (236,020     119,760   

 

 

Liabilities and Stockholders’ Equity

               

Accounts payable

  $ -        4,164       -        3       1       9,827       (3,662     10,333   

Short-term debt

    395       4       -        -        -        173       -        572   

Accrued income and other taxes

    -        173       -        6       -        2,732       -        2,911   

Employee benefit obligations

    -        461       -        -        -        217       -        678   

Other accruals

    119       623       -        32       14       1,053       -        1,841   

 

 

Total Current Liabilities

    514       5,425       -        41       15       14,002       (3,662     16,335   

Long-term debt

    9,049       5,210       -        1,250       499       5,088       -        21,096   

Asset retirement obligations and accrued environmental costs

    -        1,270       -        -        -        7,889       -        9,159   

Joint venture acquisition obligation

    -        -        -        -        -        2,203       -        2,203   

Deferred income taxes

    54       320       -        14       9       14,348       -        14,745   

Employee benefit obligations

    -        2,049       -        -        -        798       -        2,847   

Other liabilities and deferred credits*

    33,564       22,942       -        79       24       17,778       (72,549     1,838   

 

 

Total Liabilities

    43,181       37,216       -        1,384       547       62,106       (76,211     68,223   

Retained earnings

    32,964       31,925       -        (34     (51     37,440       (62,718     39,526   

Other common stockholders’ equity

    11,311       65,308       2       134       77       31,846       (97,091     11,587   

Noncontrolling interests

    -        -        -        -        -        424       -        424   

 

 

Total Liabilities and Stockholders’ Equity

  $ 87,456       134,449       2       1,484       573       131,816       (236,020     119,760   

 

 
Balance Sheet   December 31, 2012  

Assets

               

Cash and cash equivalents

  $ 2       12       6       50       2       3,546       -        3,618   

Restricted cash

    748       -        -        -        -        -        -        748   

Accounts and notes receivable**

    64       2,711       -        -        -        11,494       (5,087     9,182   

Inventories

    -        57       -        -        -        908       -        965   

Prepaid expenses and other current assets

    19       847       -        1       -        8,609       -        9,476   

 

 

Total Current Assets

    833       3,627       6       51       2       24,557       (5,087     23,989   

Investments, loans and long-term receivables*

    80,910       114,314       759       1,455       578       44,739       (217,749     25,006   

Net properties, plants and equipment

    -        8,771       -        -        -        58,492       -        67,263   

Other assets

    55       216       -        2       3       610       -        886   

 

 

Total Assets

  $ 81,798       126,928       765       1,508       583       128,398       (222,836     117,144   

 

 

Liabilities and Stockholders’ Equity

               

Accounts payable**

  $ -        5,531       -        4       1       9,564       (5,087     10,013   

Short-term debt

    (5     4       750       -        -        206       -        955   

Accrued income and other taxes

    -        104       -        3       -        3,259       -        3,366   

Employee benefit obligations

    -        485       -        -        -        257       -        742   

Other accruals

    209       636       9       15       4       1,494       -        2,367   

 

 

Total Current Liabilities

    204       6,760       759       22       5       14,780       (5,087     17,443   

Long-term debt

    9,453       5,215       -        1,250       499       4,353       -        20,770   

Asset retirement obligations and accrued environmental costs

    -        1,250       -        -        -        7,697       -        8,947   

Joint venture acquisition obligation

    -        -        -        -        -        2,810       -        2,810   

Deferred income taxes

    15       598       -        16       7       12,549       -        13,185   

Employee benefit obligations

    -        2,464       -        -        -        882       -        3,346   

Other liabilities and deferred credits*

    30,938       19,916       -        117       50       21,174       (69,979     2,216   

 

 

Total Liabilities

    40,610       36,203       759       1,405       561       64,245       (75,066     68,717   

Retained earnings

    28,815       24,041       4       (78     (73     30,778       (48,149     35,338   

Other common stockholders’ equity

    12,373       66,684       2       181       95       32,935       (99,621     12,649   

Noncontrolling interests

    -        -        -        -        -        440       -        440   

 

 

Total Liabilities and Stockholders’ Equity

  $ 81,798       126,928       765       1,508       583       128,398       (222,836     117,144   

 

 

  *Includes intercompany loans.

**Revised to conform to current-year presentation in the ConocoPhillips Company and All Other Subsidiaries columns at December 31, 2012. There was no impact to Total Consolidated balances.

 

30


Table of Contents
    Millions of Dollars  
Statement of Cash Flows   Nine Months Ended September 30, 2013  
      ConocoPhillips     ConocoPhillips
Company
    ConocoPhillips
Australia Funding
Company
    ConocoPhillips
Canada Funding
Company I
    ConocoPhillips
Canada Funding
Company II
    All Other
Subsidiaries
    Consolidating
Adjustments
    Total
Consolidated
 

Cash Flows From Operating Activities

               

Net cash provided by (used in) continuing operating activities

  $ 1,717       2,618       (2     4       -       9,559       (1,955     11,941   

Net cash provided by discontinued operations

    -        -       -       -       -       631       (396     235   

 

 

Net Cash Provided by (Used in) Operating Activities

    1,717       2,618       (2     4       -       10,190       (2,351     12,176   

 

 

Cash Flows From Investing Activities

               

Capital expenditures and investments

    -       (1,795     -       -       -       (9,825     339       (11,281)   

Proceeds from asset dispositions

    -       581       -       -       -       2,646       (52     3,175   

Net purchases of short-term investments

    -       -       -       -       -       1       -        

Long-term advances/loans—related parties

    -       (283     -       -       -       (715     998        

Collection of advances/loans—related parties

    -       266       750       -       -       2,026       (2,912     130   

Other

    -       3       -       -       -       (54     -       (51)   

 

 

Net cash provided by (used in) continuing investing activities

    -       (1,228     750       -       -       (5,921     (1,627     (8,026)   

Net cash used in discontinued operations

    -       -       -       -       -       (540     -       (540)   

 

 

Net Cash Provided by (Used in) Investing Activities

    -       (1,228     750       -       -       (6,461     (1,627     (8,566)   

 

 

Cash Flows From Financing Activities

               

Issuance of debt

    -       697       -       -       -       301       (998      

Repayment of debt

    -       (1,939     (750     -       -       (1,169     2,912       (946)   

Change in restricted cash

    748       -       -       -       -       -       -       748   

Issuance of company common stock

    12       -       -       -       -       -       -       12   

Dividends paid

    (2,481     -       (4     -       -       (2,257     2,261       (2,481)   

Other

    2       39       -       -       -       (346     (288     (593)   

 

 

Net cash used in continuing financing activities

    (1,719     (1,203     (754     -       -       (3,471     3,887       (3,260)   

Net cash used in discontinued operations

    -       -       -       -       -       (91     91        

 

 

Net Cash Used in Financing Activities

    (1,719     (1,203     (754     -       -       (3,562     3,978       (3,260)   

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

    -       (9     -       -       -       (76     -       (85)   

 

 

Net Change in Cash and Cash Equivalents

    (2     178       (6     4       -       91       -       265   

Cash and cash equivalents at beginning of period

    2       12       6       50       2       3,546       -       3,618   

 

 

Cash and Cash Equivalents at End of Period

  $ -       190       -       54       2       3,637       -       3,883   

 

 
Statement of Cash Flows   Nine Months Ended September 30, 2012  

Cash Flows From Operating Activities

               

Net cash provided by continuing operating activities

  $ 3,530       12,271       2       7       -       4,247       (10,469     9,588   

Net cash provided by (used in) discontinued operations

    -       479       -       -       -       (15     -       464   

 

 

Net Cash Provided by Operating Activities

    3,530       12,750       2       7       -       4,232       (10,469     10,052   

 

 

Cash Flows From Investing Activities

               

Capital expenditures and investments

    (317     (5,558     -       -       -       (9,531     4,686       (10,720)   

Proceeds from asset dispositions

    14       933       -       -       -       2,086       (945     2,088   

Net sales of short-term investments

    -       -       -       -       -       597       -       597   

Long-term advances/loans—related parties

    -       (74     -       -       -       (2,881     2,955        

Collection of advances/loans—related parties

    -       133       -       -       -       1,092       (1,125     100   

Other

    -       4       -       -       -       171       -       175   

 

 

Net cash used in continuing investing activities

    (303     (4,562     -       -       -       (8,466     5,571       (7,760)   

Net cash provided by (used in) discontinued operations

    -       (232     -       -       -       7,395       (8,101     (938)   

 

 

Net Cash Used in Investing Activities

    (303     (4,794     -       -       -       (1,071     (2,530     (8,698)   

 

 

Cash Flows From Financing Activities

               

Issuance of debt

    485       3,000       -       -       -       55       (3,055     485   

Repayment of debt

    (1,576     (9,241     -       -       -       (177     9,326       (1,668)   

Special cash distribution from Phillips 66

    7,818       -       -       -       -       -       -       7,818   

Change in restricted cash

    (2,468     -       -       -       -       -       -       (2,468)   

Issuance of company common stock

    83       -       -       -       -       -       -       83   

Repurchase of company common stock

    (5,098     -       -       -       -       -       -       (5,098)   

Dividends paid

    (2,469     -       -       -       -       (4,822     4,822       (2,469)   

Other

    (1     63       -       -       -       (1,540     931       (547)   

 

 

Net cash used in continuing financing activities

    (3,226     (6,178     -       -       -       (6,484     12,024       (3,864)   

Net cash provided by (used in) discontinued operations

    -       (3,786     -       -       -       792       975       (2,019)   

 

 

Net Cash Used in Financing Activities

    (3,226     (9,964     -       -       -       (5,692     12,999       (5,883)   

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

    -       (8     -       -       -       25       -       17   

 

 

Net Change in Cash and Cash Equivalents

    1       (2,016     2       7       -       (2,506     -       (4,512)   

Cash and cash equivalents at beginning of period

    -       2,028       1       37       1       3,713       -       5,780   

 

 

Cash and Cash Equivalents at End of Period

  $ 1       12       3       44       1       1,207       -       1,268   

 

 

 

 

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The Company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 52.

Due to the separation of our downstream businesses in 2012, the sale of our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) on October 31, 2013, and the intention to sell our Nigerian and Algerian businesses, which are all reported as discontinued operations, income (loss) from continuing operations is more representative of ConocoPhillips’ earnings. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on production and proved reserves. Headquartered in Houston, Texas, we have operations and activities in 29 countries. At September 30, 2013, we had approximately 18,000 employees worldwide and total assets of $120 billion.

Discontinued Operations

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our “Downstream business”), were transferred to Phillips 66. As part of our asset disposition program, in the fourth quarter of 2012, we agreed to sell our interest in Kashagan and our Nigerian and Algerian businesses. Results of operations related to Phillips 66, Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. Our asset base reflects our legacy as a major company with a strategic focus on higher-margin developments. Our diverse portfolio primarily includes resource-rich North American shale and oil sands assets; lower-risk legacy assets in Alaska, Europe, Asia and Australia; several major international developments; and a growing conventional and unconventional inventory of global exploration prospects. Our value proposition to our shareholders is to deliver production and cash margin growth, competitive returns on capital, and a compelling dividend, while keeping our fundamental commitment to safety, operating excellence and environmental stewardship. We expect to achieve this value proposition through optimizing our portfolio, investing in high-margin developments, applying technical capability and maintaining financial flexibility.

 

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In the third quarter of 2013, we achieved production of 1,514 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 44 MBOED. Consistent with our commitment to offer our shareholders a compelling dividend, in July 2013, our Board of Directors increased our quarterly dividend by 4.5 percent to $0.69 per share. Through September 2013, we generated $11.9 billion in cash from continuing operations, paid dividends on our common stock of $2.5 billion, funded an $11.9 billion capital program and continued to progress the asset disposition program.

During the first nine months of 2013, we received proceeds from dispositions of $3.2 billion, which mainly resulted from:

 

    The sale of our Clyden undeveloped oil sands leasehold, located in Canada.
    The disposition of our 39 percent equity investment in Phoenix Park Gas Processors Limited, located in Trinidad and Tobago.
    The sale of certain properties in the Cedar Creek Anticline, located in North Dakota and Montana.
    The disposition of a portion of our working interests in the Poseidon discovery in the Browse Basin and the Goldwyer Shale in the Canning Basin.
    The disposition of certain properties located in southwest Louisiana.
    The sale of our 10 percent interest in the Interconnector Pipeline, located in Europe.

On October 31, 2013, we received additional proceeds of $5.4 billion from the disposition of our 8.4 percent interest in Kashagan. As part of our 2012–2013 disposition program, we have generated $10.7 billion in proceeds through October 31, 2013, which has exceeded our goal of raising $8–$10 billion in proceeds from disposition of non-strategic assets during 2012 and 2013. The previously announced sales of Nigeria, excluding Brass LNG, and Algeria are targeted to close by the end of 2013 and generate approximately $3.4 billion in proceeds, plus customary adjustments. The sale of Brass LNG is targeted to close in the first quarter of 2014 and would generate approximately $105 million in proceeds.

Because we participate in a capital-intensive industry, we make significant investments to acquire acreage, explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, and construct pipelines and liquefied natural gas (LNG) facilities. We expect our full-year 2013 capital program will be approximately $16 billion for continuing operations and $0.6 billion for discontinued operations. We use a disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on higher-margin liquids plays and limited investment in North American conventional natural gas. As investments bring more liquids production online, we expect a corresponding shift in our production mix. However, there are often long lead times from the time we make an investment to the time the investment is operational and begins generating financial returns. In the near-term, we plan to fund a portion of our capital program with the proceeds from asset dispositions. Over the next five years, our investment in high-margin developments should position us to deliver 3 to 5 percent annual production volume and margin growth, enabling us to fund our capital program organically.

Business Environment

The business environment for the energy industry has historically experienced many challenges which have influenced our operations and profitability, largely due to factors beyond our control, such as the global financial crisis and recession which began in 2008, geopolitical events or fears thereof, environmental laws, tax regulations, governmental policies, and weather-related disruptions. More recently, North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, as a result of advances in technology responsible for the rapid growth of shale production, successful development in the deepwater Gulf of Mexico and rising production from the Canadian oil sands. These dynamics generally influence world energy markets and commodity prices. The most significant factor impacting our profitability and related reinvestment of operating cash flows into our business is commodity prices, which can be very volatile; therefore, our strategy is to maintain a strong balance sheet with a diverse portfolio of assets, which we believe will provide the financial flexibility to withstand challenging business cycles.

 

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The following table depicts the average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:

 

     Dollars Per Unit  
  

 

 

 
     Three Months Ended
September 30
    Nine Months Ended
September 30
 
  

 

 

   

 

 

 
     2013     2012      2013      2012   
  

 

 

   

 

 

 

Market Indicators

         

WTI (per barrel)

   $ 105.80       92.11        98.07        96.18   

Dated Brent (per barrel)

     110.32       109.61        108.44        112.09   

U.S. Henry Hub first of month (per million British thermal units)

     3.58       2.80        3.67        2.58   

 

 

Industry crude prices for WTI increased 15 percent in the third quarter of 2013, compared with the same period in 2012, as new infrastructure allowed increased movement of physical barrels away from Cushing, Oklahoma, and toward the U.S. Gulf Coast refining centers. Brent prices remained relatively flat in the third quarter of 2013, as growth in global oil demand was met by rising production, primarily stemming from U.S. oil production.

Henry Hub natural gas prices increased 28 percent in the third quarter of 2013, compared with the same period in 2012, as storage inventories were much lower in 2013.

The expansion in shale production has also helped boost supplies of natural gas liquids, resulting in downward pressure on natural gas liquids prices in the United States. As a result, our domestic realized natural gas liquids price declined 17 percent in the first nine months of 2013, compared with the same period of 2012. Bitumen prices continued to strengthen during the third quarter of 2013, as a result of fewer infrastructure constraints downstream of the Hardisty Terminal, which have more than offset the increase in supplies. Our realized bitumen price was $76.06 per barrel in the third quarter of 2013, an increase of 34 percent compared with the third quarter of 2012.

Key Operating and Financial Highlights

Significant highlights during the third quarter of 2013 included the following:

 

  Achieved third-quarter guidance with production of 1,514 MBOED, including continuing operations of 1,470 MBOED, which reflects two months of disruptions in Libya, and discontinued operations of 44 MBOED.
  Successfully completed major turnarounds and tie-in activities as planned.
  Eagle Ford, Bakken and Permian production increased 40 percent compared with third-quarter 2012.
  Started up major projects at Christina Lake Phase E in July and Ekofisk South in October, with final preparations underway for full-field startup at Gumusut, Jasmine and Siakap North-Petai.
  High level of exploration activity continues with drilling in the Gulf of Mexico, Australia’s Browse Basin, and unconventional plays in Canada and the Lower 48.
  Completed sale of Clyden and our interest in Phoenix Park.

Outlook

Fourth-quarter production from continuing operations is expected to be 1,485 to 1,525 MBOED, which reflects a 50 MBOED reduction for the assumed closure of the Es Sider crude oil export terminal in Libya for the entire quarter. Full-year 2013 production from continuing operations is expected to be 1,505 to 1,515 MBOED. Full-year production from discontinued operations is expected to be 35 to 45 MBOED.

 

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Freeport LNG

In July 2013, we reached agreement with Freeport LNG to terminate our long-term agreement at the Freeport LNG Terminal, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. Upon satisfaction of these conditions, currently expected to occur by the end of the first quarter of 2014, we will pay Freeport LNG a termination fee of approximately $600 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, will result in a net cash outflow of approximately $80 million for us. When the agreement becomes effective, we also expect to recognize an after-tax charge to earnings of approximately $540 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero. As a result of this transaction, we anticipate saving approximately $50 to $60 million per year in operating costs over the next 19 years. For additional information, see Note 4—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2013, is based on a comparison with the corresponding periods of 2012.

A summary of income (loss) from continuing operations by business segment follows:

 

     Millions of Dollars  
       Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2013     2012       2013     2012   
  

 

 

    

 

 

 

Alaska

   $ 494       535         1,719       1,706   

Lower 48 and Latin America

     498       182         878       556   

Canada

     642       (31)         780       (674)   

Europe

     284       132         976       1,190   

Asia Pacific and Middle East

     757       684         2,719       3,232   

Other International

     (2     492         26       456    

Corporate and Other

     (234     (254)         (569     (827)   

 

 

Income from continuing operations

   $ 2,439       1,740         6,529       5,639   

 

 

Earnings for ConocoPhillips increased 40 percent in the third quarter of 2013, while earnings for the nine-month period ended September 30, 2013, increased 16 percent. The improvements in the third quarter of 2013 primarily resulted from:

 

    Higher gains from asset sales. Gains realized in the third quarter of 2013 were $777 million after-tax, compared with gains of $336 million after-tax in the third quarter of 2012.
    Higher commodity prices.
    A higher proportion of production in higher-margin areas and a continued portfolio shift toward liquids.
    The absence of $170 million in additional income tax expense, as a result of legislation enacted in the United Kingdom in 2012.

 

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These items were partially offset by:

 

    Higher depreciation, depletion and amortization (DD&A) expenses, mainly due to higher volumes in the Lower 48.
    Higher operating expenses, mainly due to a $116 million after-tax charge related to a pending settlement in the Asia Pacific and Middle East segment, as well as increased production volumes and activity in the Lower 48 and the Asia Pacific region.

The increase in earnings in the nine-month period of 2013 was primarily due to:

 

    Lower impairments. Non-cash impairments for the nine-month period of 2013 totaled $20 million after-tax, compared with $550 million after-tax in the nine-month period of 2012.
    A higher proportion of production in higher-margin areas and a continued portfolio shift toward liquids.
    Higher natural gas prices.
    Lower production taxes, primarily as a result of lower production volumes and prices and higher capital spending in Alaska.
    The favorable resolution of pending claims and settlements of $234 million after-tax.
    Absence of the 2012 U.K. tax increase of $170 million and separation costs of $80 million after-tax.

These items were partially offset by:

 

    Higher DD&A expenses, mainly due to higher volumes in the Lower 48 and China.
    Lower gains from asset sales. Gains realized in the nine-month period of 2013 were $1,118 million after-tax, compared with gains of $1,557 million after-tax in the nine-month period of 2012.
    Lower crude oil, natural gas liquids and LNG prices.
    Higher operating expenses, which included a $116 million after-tax charge related to a pending settlement in Asia Pacific and Middle East, and higher dry hole expenses.

See the “Segment Results” section for additional information on our segment results.

Income Statement Analysis

Equity in earnings of affiliates increased 72 percent in third quarter and 9 percent in the nine-month period of 2013. The increases primarily resulted from:

 

    Higher earnings from FCCL Partnership, mainly as a result of higher bitumen prices and volumes.
    Higher earnings from Qatar Liquefied Gas Company Limited (3) (QG3), largely due to higher LNG volumes.

Gain on dispositions increased $951 million in the third quarter and decreased $419 million in the nine-month period of 2013. Gains realized in the third quarter of 2013 primarily resulted from the disposition of our Clyden undeveloped oil sands leasehold and the disposition of our 39 percent equity interest in Phoenix Park. Gains realized in the third quarter of 2012 mostly resulted from the disposition of our equity investment in Naryanmarneftegaz (NMNG), partly offset by the loss on further dilution of our equity interest in Australia Pacific LNG (APLNG) from 42.5 percent to 37.5 percent.

Additional gains realized in the nine-month period of 2013 mainly resulted from the disposition of our interest in the Interconnector Pipeline, partly offset by a loss on the disposition of certain properties located in the Cedar Creek Anticline. Gains in the nine-month period of 2012 also included the $937 million gain on sale of our Vietnam business and the gain on sale of the Statfjord and Alba fields located in the North Sea.

Other income increased 89 percent in the nine-month period of 2013, largely as a result of a $150 million insurance settlement associated with the Bohai Bay seepage incidents.

 

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Purchased commodities decreased 10 percent in the third quarter and 6 percent in the nine-month period of 2013, largely as a result of lower purchased natural gas volumes, partly offset by higher natural gas prices.

Production and operating expenses increased 20 percent in the third quarter and 6 percent in the nine-month period of 2013, primarily as a result of increased drilling activity and production volumes, mostly in the Lower 48, in addition to a charge related to a pending settlement in Asia Pacific and Middle East.

Selling, general and administrative expenses decreased 24 percent in the third quarter and 32 percent in the nine-month period of 2013, mainly due to lower pension settlement expense. The nine-month period of 2013 also benefitted from the absence of separation costs, as well as lower costs related to compensation and benefit plans. For additional information, see Note 19—Employee Benefit Plans, in the Notes to Consolidated Financial Statements.

Exploration expenses increased 46 percent in the third quarter and decreased 21 percent in the nine-month period of 2013. Both periods of 2013 were impacted by higher dry hole costs. The nine-month period of 2012 also included the $481 million impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of the indefinite suspension of the project.

DD&A increased 15 percent in both the third quarter and nine-month period of 2013. The increase was mostly associated with higher production volumes in the Lower 48. In addition, higher production volumes in China contributed to the increase in the nine-month period of 2013.

Impairments decreased 90 percent in the nine-month period of 2013. The nine-month period of 2012 included a $213 million impairment of capitalized project development costs associated with the Mackenzie Gas Project, in addition to an increase in the asset retirement obligation for the U.K. Don Field, which has ceased production. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 18 percent in the nine-month period of 2013, mainly as a result of lower production taxes due to lower crude oil production volumes and prices and higher capital spending in Alaska.

Interest and debt expense decreased 23 percent in the nine-month period of 2013, primarily due to lower interest expense from lower average debt levels and higher capitalized interest on projects.

See Note 22—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

 

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Summary Operating Statistics

 

     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2013      2012       2013      2012   
  

 

 

    

 

 

 

Average Net Production

           

Crude oil (MBD)*

     552        553        587        587   

Natural gas liquids (MBD)

     156        151        158        155   

Bitumen (MBD)

     107        92        105        88   

Natural gas (MMCFD)**

     3,930        4,037        3,963        4,100   

 

 

Total Production (MBOED)

     1,470        1,470        1,511        1,514   

 

 
     Dollars Per Unit  

Average Sales Prices

           

Crude oil (per barrel)

   $ 106.60        102.54        104.20        106.66   

Natural gas liquids (per barrel)

     41.14        41.08        40.64        46.84   

Bitumen (per barrel)

     76.06        56.86        57.08        56.23   

Natural gas (per thousand cubic feet)

     5.99        5.28        6.14        5.38   

 

 
     Millions of Dollars  

Exploration Expenses

           

General administrative; geological and geophysical; and lease rentals

   $ 180        146        566        452   

Leasehold impairment

     32        63        142        627   

Dry holes

     101        6        203        76   

 

 
   $ 313        215        911        1,155   

 

 

Excludes discontinued operations.

  *Thousands of barrels per day.

**Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At September 30, 2013, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

Total production from continuing operations remained flat in both the third quarter and nine-month period of 2013, compared with the corresponding periods of 2012, while average liquids production increased 2 percent over the same periods. Production increased in both periods of 2013 due to new production from major developments, mainly from the Lower 48, Christina Lake in Canada, and Malaysia; higher production in China; and increased drilling programs, mostly in western Canada, the Lower 48 and Norway. However, these increases were offset by normal field decline, the impact of the disruption in Libya, due to the closure of the Es Sider crude oil export terminal, and asset dispositions. Excluding dispositions, downtime and the impact from the closure of the Es Sider Terminal in Libya, production grew by 29 MBOED, or 2 percent, compared with the third quarter of 2012, and 51 MBOED, or 3 percent, compared with the nine-month period of 2012.

 

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Segment Results

Alaska

 

     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2013      2012       2013      2012   
  

 

 

    

 

 

 

Income From Continuing Operations (millions of dollars)

   $ 494        535         1,719        1,706   

 

 

Average Net Production

           

Crude oil (MBD)

     161        157         176        185   

Natural gas liquids (MBD)

     11        10         15        15   

Natural gas (MMCFD)

     35        51         43        55   

 

 

Total Production (MBOED)

     178        176         198        209   

 

 

Average Sales Prices

           

Crude oil (dollars per barrel)

   $ 110.95        106.53         109.14        110.54   

Natural gas (dollars per thousand cubic feet)

     4.09        3.97         4.56        4.21   

 

 

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and natural gas. As of September 30, 2013, Alaska contributed 22 percent of our worldwide liquids production and 1 percent of our natural gas production.

Alaska’s earnings decreased 8 percent in the third quarter and increased 1 percent in the nine-month period of 2013, compared with the same periods of 2012. The decrease in earnings in the third quarter of 2013 was mostly due to lower crude oil sales volumes, partly offset by higher crude oil prices and lower production taxes. The increase in earnings in the nine-month period of 2013 was mainly due to lower production taxes, which resulted from lower prices, higher 2013 capital spending and lower crude oil production volumes. Earnings also improved in the nine-month period of 2013 due to the impact of a ruling by the Federal Energy Regulatory Commission (FERC), as more fully described below. These increases to earnings were nearly offset by lower crude oil and LNG sales volumes and lower crude oil prices.

In 2012, the major owners of Trans-Alaska Pipeline System (TAPS) filed a proposed settlement with FERC to resolve pooling disputes prior to August 2012 and establish a voluntary pooling agreement to pool costs prospectively from August 2012. In July 2013, the FERC approved the proposed settlement and pooling agreement without modification. Under the terms of the agreements, we paid the other remaining owners of TAPS $355 million, including interest, in the third quarter of 2013. As a result of FERC approval of these agreements, we reduced a related accrual in the second quarter of 2013, which decreased our production and operating expenses by $97 million after-tax. The FERC ruling approving these agreements has been appealed by certain parties to the Court of Appeals for the District of Columbia.

Average production increased 1 percent in the third quarter and decreased 5 percent in the nine-month period of 2013. The increase in the third quarter of 2013 was mainly due to less turnaround activity, partly offset by normal field decline. The reduction in the nine-month period of 2013 was mostly due to normal field decline, partly offset by lower planned maintenance.

Chukchi Sea

In April 2013, we announced our 2014 Chukchi Sea exploration drilling plans are on hold given the uncertainties of evolving federal regulatory requirements and operational permitting standards. Once these requirements are clarified and better defined, we will re-evaluate our Chukchi Sea drilling plans.

 

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Lower 48 and Latin America

 

     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2013      2012       2013      2012   
  

 

 

    

 

 

 

Income From Continuing Operations (millions of dollars)

   $ 498        182         878        556   

 

 

Average Net Production

           

Crude oil (MBD)

     153        124         149        119   

Natural gas liquids (MBD)

     94        87         91        85   

Natural gas (MMCFD)

     1,511        1,507         1,490        1,489   

 

 

Total Production (MBOED)

     499        462         488        452   

 

 

Average Sales Prices

           

Crude oil (dollars per barrel)

   $ 100.25        90.06         95.92        92.84   

Natural gas liquids (dollars per barrel)

     32.57        31.40         30.52        36.89   

Natural gas (dollars per thousand cubic feet)

     3.39        2.64         3.48        2.47   

 

 

As of September 30, 2013, Lower 48 and Latin America contributed 28 percent of our worldwide liquids production and 38 percent of our natural gas production. The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states, as well as exploration activities in the Gulf of Mexico and Colombia.

Lower 48 and Latin America operations reported earnings of $498 million in the third quarter of 2013, a 174 percent increase compared with the same period in 2012. Earnings for the nine-month period of 2013 were $878 million, a 58 percent increase compared with the same period in 2012. Earnings for both periods of 2013 largely benefitted from the $288 million after-tax gain on disposition of our equity investment in Phoenix Park, higher crude oil volumes and higher crude oil and natural gas prices. These increases to earnings were partially offset by higher DD&A, due to higher crude oil production. Higher operating expenses and a $48 million after-tax charge for the Ardennes dry hole, located in the Gulf of Mexico, also partly offset the increase to earnings.

Earnings in the nine-month period of 2013 were also negatively impacted by lower natural gas liquids prices, the Thorn dry hole, located in the Gulf of Mexico, and related leasehold impairment of $68 million after-tax, and the $52 million after-tax loss on disposition of certain Cedar Creek Anticline properties. These decreases were partially offset by a $69 million after-tax gain on disposition of certain properties in southwest Louisiana.

Total average production in the Lower 48 increased 8 percent in both the third quarter and nine-month period of 2013. Average liquids production increased 17 percent and 18 percent in the third quarter and first nine months of 2013, respectively. New production, primarily from the Eagle Ford, Bakken and Permian areas, and improved drilling and well performance more than offset normal field decline and the impact from dispositions. Higher unplanned downtime also partially offset the increases in production in both periods of 2013.

Venezuela Arbitration

In September 2013, the World Bank’s International Centre for Settlement of Investment Disputes (ICSID) arbitration tribunal ruled Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in the Petrozuata and Hamaca heavy crude oil projects and the offshore Corocoro development project in June 2007. An additional arbitration phase is currently proceeding to determine the amount of damages owed to ConocoPhillips for Venezuela’s actions. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

 

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Table of Contents

Canada

 

       Three Months Ended
September 30
       Nine Months Ended
September 30
 
     2013      2012       2013      2012   
  

 

 

    

 

 

 

Income (Loss) From Continuing Operations (millions of dollars)

   $ 642        (31)         780        (674)   

 

 

Average Net Production

           

Crude oil (MBD)

     13        14         14        13   

Natural gas liquids (MBD)

     25        25         25        24   

Bitumen (MBD)

           

Consolidated operations

     13        12         12        11   

Equity affiliates

     94        80         93        77   

 

 

Total bitumen

     107        92         105        88   

Natural gas (MMCFD)

     775        874         790        867   

 

 

Total Production (MBOED)

     274        277         276        270   

 

 

Average Sales Prices

           

Crude oil (dollars per barrel)

   $ 91.81        77.19         81.71        78.44   

Natural gas liquids (dollars per barrel)

     46.90        45.31         47.07        49.43   

Bitumen (dollars per barrel)

           

Consolidated operations

     76.90        56.23         59.18        58.41   

Equity affiliates

     75.93        56.95         56.79        55.90   

Total bitumen

     76.06        56.86         57.08        56.23   

Natural gas (dollars per thousand cubic feet)

     2.42        2.05         2.86        1.88   

 

 

Our Canadian operations comprise mainly natural gas fields in western Canada and oil sands projects in the Athabasca Region of northeastern Alberta. As of September 30, 2013, Canada contributed 17 percent of our worldwide liquids production and 20 percent of our natural gas production.

Canada operations reported earnings of $642 million in the third quarter and $780 million in the nine-month period of 2013, compared with losses of $31 million and $674 million in the corresponding periods of 2012, respectively. Earnings in both periods of 2013 largely benefitted from the $461 million after-tax gain on disposition of our Clyden undeveloped oil sands leasehold and higher bitumen volumes. Higher bitumen prices also contributed to the increase in earnings in the third quarter of 2013. Additionally, earnings for the nine-month period of 2013 benefitted from the absence of a $520 million after-tax impairment of the Mackenzie Gas Project and associated undeveloped leaseholds in 2012, as well as the recognition of additional income of $224 million related to the favorable tax resolution associated with the sale of certain western Canada properties in a prior year. Higher natural gas prices also contributed to the increase in earnings in the nine-month period of 2013.

Total average production decreased 1 percent in the third quarter and increased 2 percent in the nine-month period of 2013, while average liquids production increased 11 percent and 15 percent over the same periods, respectively. Increased production from Christina Lake Phase D, new production from Christina Lake Phase E, new wells in western Canada and lower royalty impacts more than offset normal field decline in both periods of 2013. However, higher planned and unplanned maintenance more than offset these improvements in the third quarter of 2013. In the nine-month period of 2013, lower natural gas curtailments also contributed to the increases, which were partly offset by higher planned and unplanned maintenance.

 

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Table of Contents

Europe

 

     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2013      2012       2013      2012   
  

 

 

    

 

 

 

Income From Continuing Operations (millions of dollars)

   $ 284        132         976        1,190   

 

 

Average Net Production

           

Crude oil (MBD)

     111        117         112        137   

Natural gas liquids (MBD)

     5               5         

Natural gas (MMCFD)

     357        414         409        529   

 

 

Total Production (MBOED)

     176        191         185        233   

 

 

Average Sales Prices

           

Crude oil (dollars per barrel)

   $ 112.28        109.67         110.40        113.69   

Natural gas liquids (dollars per barrel)

     57.36        57.62         56.28        56.97   

Natural gas (dollars per thousand cubic feet)

     10.48        8.87         10.53        9.53   

 

 

The Europe segment consists of operations principally located in Norway and the United Kingdom, as well as exploration activities in Poland and Greenland. As of September 30, 2013, our Europe operations contributed 14 percent of our worldwide liquids production and 10 percent of our natural gas production.

Europe operations reported earnings of $284 million in the third quarter of 2013, a 115 percent increase compared with the same period in 2012. Earnings for the nine-month period of 2013 were $976 million, an 18 percent decrease compared with the same period in 2012. The increase in earnings in the third quarter of 2013 was primarily due to the absence of the recognition of $170 million in additional income tax expense in the third quarter of 2012, as a result of legislation enacted in the United Kingdom, which restricted corporate tax relief on decommissioning costs to 50 percent.

The decrease in earnings for the nine-month period of 2013 was mainly the result of lower crude oil and natural gas volumes and lower gains from asset dispositions. Gains realized in the nine-month period of 2012 included the $285 million after-tax gain on sale of our interests in the Statfjord and Alba fields, compared with the $83 million after-tax gain on sale of our interest in the Interconnector Pipeline in 2013. These decreases were partly offset by the absence of the $170 million U.K. tax increase in 2012, higher gains from foreign currency transactions and lower impairments.

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