Form 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, 2012

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

incorporation or organization)

 

(I.R.S. Employer

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 1,213,894,641 shares of common stock, $.01 par value, outstanding at September 30, 2012.

 

 

 


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   

Consolidated Statement of Changes in Equity

     5   

Notes to Consolidated Financial Statements

     6   

Supplementary Information—Condensed Consolidating Financial Information

     28   

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

     33   

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     54   

Item 4. Controls and Procedures

     54   

Part II—Other Information

  

Item 1. Legal Proceedings

     55   

Item 1A. Risk Factors

     56   

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

     56   

Item 6. Exhibits

     57   

Signature

     58   


Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

 

Consolidated Income Statement    ConocoPhillips

 

     Millions of Dollars  
     Three Months
Ended September 30
    Nine Months
Ended September 30
 
     2012     2011     2012     2011  
  

 

 

   

 

 

 

Revenues and Other Income

        

Sales and other operating revenues

   $ 14,520       16,506       43,492       49,462  

Equity in earnings of affiliates

     409       443       1,424       1,144  

Gain (loss) on dispositions

     118       (260     1,641       388  

Other income

     42       6       168       172  

 

 

Total Revenues and Other Income

     15,089       16,695       46,725       51,166  

 

 

Costs and Expenses

        

Purchased commodities

     6,436       7,976       18,314       22,615  

Production and operating expenses

     1,711       1,767       5,232       4,941  

Selling, general and administrative expenses

     330       145       892       596  

Exploration expenses

     219       266       1,168       706  

Depreciation, depletion and amortization

     1,699       1,645       4,948       5,339  

Impairments

                   296         

Taxes other than income taxes

     676       904       2,683       2,986  

Accretion on discounted liabilities

     102       107       314       319  

Interest and debt expense

     161       230       548       729  

Foreign currency transaction (gains) losses

     (1     50       18       75  

 

 

Total Costs and Expenses

     11,333       13,090       34,413       38,306  

 

 

Income from continuing operations before income taxes

     3,756       3,605       12,312       12,860  

Provision for income taxes

     1,945       2,110       6,505       6,748  

 

 

Income From Continuing Operations

     1,811       1,495       5,807       6,112  

Income from discontinued operations

     2       1,136       1,250       2,980  

 

 

Net income

     1,813       2,631       7,057       9,092  

Less: net income attributable to noncontrolling interests

     (15     (15     (55     (46

 

 

Net Income Attributable to ConocoPhillips

   $ 1,798       2,616       7,002       9,046  

 

 

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

        

Basic

        

Continuing operations

   $ 1.47       1.09       4.60       4.35  

Discontinued operations

            0.84       1.00       2.13  

 

 

Net Income Attributable to ConocoPhillips Per Share of
Common Stock

   $ 1.47       1.93       5.60       6.48  

 

 

Diluted

        

Continuing operations

   $ 1.46       1.08       4.56       4.31  

Discontinued operations

            0.83       0.99       2.11  

 

 

Net Income Attributable to ConocoPhillips Per Share of
Common Stock

   $ 1.46        1.91        5.55        6.42   

 

 

Dividends Paid Per Share of Common Stock (dollars)

   $ 0.66       0.66       1.98       1.98  

 

 

Average Common Shares Outstanding (in thousands)

        

Basic

     1,220,462       1,357,710       1,250,641       1,396,216  

Diluted

     1,229,343       1,369,562       1,260,212       1,408,846  

 

 

See Notes to Consolidated Financial Statements.

 

1


Table of Contents
              
Consolidated Statement of Comprehensive Income      ConocoPhillips   

 

                                                           
     Millions of Dollars  
     Three Months Ended
September 30
    Nine Months Ended
September 30
 
     2012     2011     2012     2011  
  

 

 

   

 

 

 

Net Income

   $ 1,813       2,631       7,057       9,092  

 

 

Other comprehensive income (loss)

        

Defined benefit plans

        

Prior service cost arising during the period

                            

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

     (1     1       (3     2  

 

 

Net change

     (1     1       (3     2  

 

 

Net actuarial loss arising during the period

     (432            (470       

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

     189       70       327       173  

 

 

Net change

     (243     70       (143     173  

Nonsponsored plans*

            6       5       17  

Income taxes on defined benefit plans

     94       (29     67       (69

 

 

Defined benefit plans, net of tax

     (150     48       (74     123  

 

 

Unrealized holding gain on securities**

                   1       8  

Reclassification adjustment for gain included in net income

                          (255

Income taxes on unrealized holding gain on securities

                          89  

 

 

Unrealized gain (loss) on securities, net of tax

                   1       (158

 

 

Foreign currency translation adjustments

     925       (2,486     1,244       (1,023

Reclassification adjustment for loss included in net income

     (320     (516     (319     (516

Income taxes on foreign currency translation adjustments

     7       32       21       3  

 

 

Foreign currency translation adjustments, net of tax

     612       (2,970     946       (1,536

 

 

Hedging activities

                   6       1  

Income taxes on hedging activities

                            

 

 

Hedging activities, net of tax

                   6       1  

 

 

Other Comprehensive Income (Loss), Net of Tax

     462       (2,922     879       (1,570

 

 

Comprehensive Income (Loss)

     2,275       (291     7,936       7,522  

Less: comprehensive income attributable to noncontrolling interests

     (15     (15     (55     (46

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

   $ 2,260       (306     7,881       7,476  

 

 

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

**Available-for-sale securities of LUKOIL.

See Notes to Consolidated Financial Statements.

 

2


Table of Contents
              
Consolidated Balance Sheet      ConocoPhillips   

 

                             
     Millions of Dollars  
     September 30
2012
    December 31    
2011**
 
  

 

 

 

Assets

    

Cash and cash equivalents

   $ 1,268       5,780       

Short-term investments*

            581       

Restricted cash

     2,468       —       

Accounts and notes receivable (net of allowance of $12 million in 2012 and $30 million in 2011)

     9,021        14,648       

Accounts and notes receivable—related parties

     162       1,878       

Inventories

     1,176       4,631       

Prepaid expenses and other current assets

     1,686       2,700       

 

 

Total Current Assets

     15,781       30,218       

Investments and long-term receivables

     23,500       32,108       

Loans and advances—related parties

     1,564       1,675       

Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $59,890 million in 2012 and $65,029 million in 2011)

     73,612        84,180       

Goodwill

            3,332       

Intangibles

     10       745       

Other assets

     902       972       

 

 

Total Assets

   $ 115,369       153,230       

 

 

Liabilities

    

Accounts payable

   $ 9,133       17,973       

Accounts payable—related parties

     849       1,680       

Short-term debt

     2,335       1,013       

Accrued income and other taxes

     2,837       4,220       

Employee benefit obligations

     678       1,111       

Other accruals

     1,551       2,071       

 

 

Total Current Liabilities

     17,383       28,068       

Long-term debt

     18,782       21,610       

Asset retirement obligations and accrued environmental costs

     8,421       9,329       

Joint venture acquisition obligation—related party

     3,006       3,582       

Deferred income taxes

     14,155       18,040       

Employee benefit obligations

     3,222       4,068       

Other liabilities and deferred credits

     2,523       2,784       

 

 

Total Liabilities

     67,492       87,481       

 

 

Equity

    

Common stock (2,500,000,000 shares authorized at $.01 par value)

    

Issued (2012—1,757,089,796 shares; 2011—1,749,550,587 shares)

    

Par value

     18       17       

Capital in excess of par

     45,130       44,725       

Treasury stock (at cost: 2012—543,195,155 shares; 2011—463,880,628 shares)

     (36,845     (31,787)     

Accumulated other comprehensive income

     4,339       3,246       

Unearned employee compensation

            (11)     

Retained earnings

     34,764       49,049       

 

 

Total Common Stockholders’ Equity

     47,406       65,239       

Noncontrolling interests

     471       510       

 

 

Total Equity

     47,877       65,749       

 

 

Total Liabilities and Equity

   $ 115,369       153,230       

 

 
*Includes marketable securities of:    $        232       

**Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income, in the Notes to

    Consolidated Financial Statements.

  

  

See Notes to Consolidated Financial Statements.

 

3


Table of Contents
              
Consolidated Statement of Cash Flows      ConocoPhillips   

 

                             
     Millions of Dollars  
     Nine Months Ended
September 30
 
     2012     2011  
  

 

 

 

Cash Flows From Operating Activities

    

Net income

   $ 7,057       9,092  

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

    

Depreciation, depletion and amortization

     4,948       5,339  

Impairments

     296         

Dry hole costs and leasehold impairments

     703       290  

Accretion on discounted liabilities

     314       319  

Deferred taxes

     878       230  

Undistributed equity earnings

     (401     (292

Gain (loss) on dispositions

     (1,641     (388

Income from discontinued operations

     (1,250     (2,980

Other

     (54     (180

Working capital adjustments

    

Decrease (increase) in accounts and notes receivable

     (1,804     (109

Decrease (increase) in inventories

     3       8  

Decrease (increase) in prepaid expenses and other current assets

     456       (223

Increase (decrease) in accounts payable

     894       893  

Increase (decrease) in taxes and other accruals

     (553     (603

 

 

Net cash provided by continuing operating activities

     9,846       11,396  

Net cash provided by discontinued operations

     206       2,438  

 

 

Net Cash Provided by Operating Activities

     10,052       13,834  

 

 

Cash Flows From Investing Activities

    

Capital expenditures and investments

     (11,337     (8,747

Proceeds from asset dispositions

     2,088       1,954  

Net sales (purchases) of short-term investments

     597       (1,623

Long-term advances/loans—related parties

     (19     (14

Collection of advances/loans—related parties

     100       88  

Other

     177       39  

 

 

Net cash used in continuing investing activities

     (8,394     (8,303

Net cash provided by (used in) discontinued operations

     (304     164  

 

 

Net Cash Used in Investing Activities

     (8,698     (8,139

 

 

Cash Flows From Financing Activities

    

Issuance of debt

     485         

Repayment of debt

     (1,668     (419

Special cash distribution from Phillips 66

     7,818         

Change in restricted cash

     (2,468       

Issuance of company common stock

     83       109  

Repurchase of company common stock

     (5,098     (7,984

Dividends paid

     (2,469     (2,761

Other

     (547     (542

 

 

Net cash used in continuing financing activities

     (3,864     (11,597

Net cash used in discontinued operations

     (2,019     (21

 

 

Net Cash Used in Financing Activities

     (5,883     (11,618

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

     17       (94

 

 

Net Change in Cash and Cash Equivalents

     (4,512     (6,017

Cash and cash equivalents at beginning of period

     5,780       9,454  

 

 

Cash and Cash Equivalents at End of Period

   $ 1,268       3,437  

 

 

See Notes to Consolidated Financial Statements.

 

4


Table of Contents
              
Consolidated Statement of Changes in Equity      ConocoPhillips   

 

                                                                                                                       
     Millions of Dollars  
     Attributable to ConocoPhillips              
     Common Stock                                 
    

Par

Value

    

Capital in

Excess of

Par

    

Treasury

Stock

   

Accum. Other

Comprehensive

Income

    

Unearned

Employee

Compensation

   

Retained

Earnings

    Noncontrolling
Interests
    Total  
  

 

 

 

December 31, 2011*

   $ 17        44,725        (31,787     3,246        (11     49,049       510       65,749  

Net income

                  7,002       55       7,057  

Other comprehensive income

             879              879  

Cash dividends paid

                  (2,469       (2,469

Repurchase of company common stock

           (5,098              (5,098

Distributions to noncontrolling interests and other

                    (63     (63

Distributed under benefit plans

     1        405        40                446  

Recognition of unearned compensation

                11            11  

Separation of Downstream business

             214          (18,837     (31     (18,654

Other

                  19         19  

 

 

September 30, 2012

   $ 18        45,130        (36,845     4,339               34,764       471       47,877  

 

 
* Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements.

 

5


Table of Contents

 

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 2011 Annual Report on Form 10-K.

The results of operations for our refining, marketing and transportation businesses; most of our Midstream segment; our Chemicals segment; and our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our “Downstream business”), have been classified as discontinued operations for all periods presented. See Note 2—Separation of Downstream Business, for additional information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

Note 2—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. After the close of the New York Stock Exchange on April 30, 2012, the shareholders of record as of 5:00 p.m. Eastern time on April 16, 2012 (the Record Date), received one share of Phillips 66 common stock for every two ConocoPhillips common shares held as of the Record Date.

In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution, primarily using the proceeds from the private placement of $5.8 billion in Senior Notes issued by Phillips 66 in March 2012, as well as a portion of the approximately $3.6 billion in cash transferred to Phillips 66 at separation, consisting of funds received from the $2.0 billion term loan that Phillips 66 entered into immediately prior to the separation, and approximately $1.6 billion of cash held by Phillips 66 subsidiaries. Pursuant to a private letter ruling from the Internal Revenue Service, the principal funds from the special cash distribution will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. At September 30, 2012, the remaining balance of the cash distribution was $2,468 million and was included in the “Restricted cash” line on our consolidated balance sheet.

In order to effect the separation and govern our relationship with Phillips 66 after the separation, we entered into a Separation and Distribution Agreement, an Indemnification and Release Agreement, an Intellectual Property Assignment and License Agreement, a Tax Sharing Agreement, an Employee Matters Agreement and a Transition Services Agreement. The Separation and Distribution Agreement governs the separation of the Downstream business, the transfer of assets and other matters related to our relationship with Phillips 66. The Indemnification and Release Agreement provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters. The Intellectual Property Assignment and License Agreement governs the allocation of intellectual property rights and assets between Phillips 66 and us.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Phillips 66 and ConocoPhillips with respect to taxes, tax attributes, tax returns, tax proceedings and certain other tax matters. In addition, the Tax Sharing Agreement imposes certain restrictions on Phillips 66 and its subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that

 

6


Table of Contents

are designed to preserve the tax-free status of the distribution and certain related transactions. The Tax Sharing Agreement sets forth the obligations of Phillips 66 and us as to the filing of tax returns, the administration of tax proceedings and assistance and cooperation on tax matters.

The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees and non-employee directors of Phillips 66 and ConocoPhillips, and generally allocates liabilities and responsibilities relating to employee compensation, benefit plans and programs. The Employee Matters Agreement provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by ConocoPhillips. In addition, the Employee Matters Agreement provides that each of the parties will be responsible for their respective current employees and compensation plans for such current employees, and we will be responsible for all liabilities relating to former employees. The Employee Matters Agreement sets forth the general principles relating to employee matters and also addresses any special circumstances during the transition period. The Employee Matters Agreement also provides that (i) the distribution does not constitute a change in control under existing plans, programs, agreements or arrangements, and (ii) the distribution and the assignment, transfer or continuation of the employment of employees with another entity will not constitute a severance event under the applicable plans, programs, agreements or arrangements.

The Transition Services Agreement sets forth the terms on which we will provide Phillips 66, and Phillips 66 will provide to us, certain services or functions Phillips 66 and ConocoPhillips historically have shared. Transition services include administrative, payroll, human resources, data processing, environmental health and safety, financial audit support, financial transaction support, and other support services, information technology systems and various other corporate services. The agreement provides for the provision of specified transition services, generally for a period of up to 12 months, with a possible extension of 6 months (an aggregate of 18 months), on a cost or a cost-plus basis.

 

7


Table of Contents

The following table presents the carrying value of the major categories of assets and liabilities of Phillips 66, immediately preceding the separation of our Downstream business on April 30, 2012, excluded from our consolidated balance sheet at September 30, 2012:

 

              
    

Millions of

Dollars

 
  

 

 

 

Assets

  

Cash and cash equivalents

   $ 3,603  

Accounts and notes receivable

     7,295  

Accounts and notes receivable—related parties

     1,501  

Inventories

     5,017  

Prepaid expenses and other current assets

     996  

 

 

Total current assets of discontinued operations

     18,412  

Investments and long-term receivables

     10,826  

Loans and advances—related parties

     1  

Net properties, plants and equipment

     15,258  

Goodwill

     3,330  

Intangibles

     730  

Other assets

     95  

 

 

Total assets of discontinued operations

   $ 48,652  

 

 

Liabilities

  

Accounts payable

   $ 12,064  

Accounts payable—related parties

     938  

Short-term debt

     7,814  

Accrued income and other taxes

     493  

Employee benefit obligations

     219  

Other accruals

     952  

 

 

Total current liabilities of discontinued operations

     22,480  

Long-term debt

     175  

Asset retirement obligations and accrued environmental costs

     771  

Deferred income taxes

     4,980  

Employee benefit obligations

     1,166  

Other liabilities and deferred credits

     426  

 

 

Total liabilities of discontinued operations

   $ 29,998  

 

 

Sales and other operating revenues and income from discontinued operations were as follows:

 

                                                           
     Millions of Dollars  
     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2012        2011        2012        2011  
  

 

 

    

 

 

 

Sales and other operating revenues from discontinued operations

   $ 2        50,590        62,109        147,954  

 

 

Income from discontinued operations before-tax

   $ 2        1,574        1,792        4,307  

Income tax expense

             438        542        1,327  

 

 

Income from discontinued operations

   $ 2        1,136        1,250        2,980  

 

 

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 2011.

 

8


Table of Contents

Prior to the separation, commodity sales to Phillips 66 were $4,973 million for the nine-month period ended September 30, 2012, and $4,012 million and $11,611 million for the three- and nine-month periods ended September 30, 2011. Prior to the separation, commodity purchases from Phillips 66 were $166 million for the nine-month period ended September 30, 2012, and $129 million and $393 million for the three- and nine-month periods ended September 30, 2011. 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. Although we expect certain transactions related to the sale and purchase of crude oil, natural gas and products to continue in the future with Phillips 66, the expected continuing cash flows are not considered significant; thus, the operations and cash flows of our former Downstream business are considered to be eliminated from our ongoing operations.

Note 3—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 a liquefied natural gas (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. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $579 million at September 30, 2012, and $612 million at December 31, 2011. 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. We 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)

As of the third quarter of 2012, 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.

No other financial support that was not previously contractually required was provided to APLNG as of the nine months ended September 30, 2012, or is expected to be provided in the future. In addition, unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 6—Investments, Loans and Long-Term Receivables, and Note 12—Guarantees, for additional information.

 

9


Table of Contents

Note 4—Inventories

Inventories consisted of the following:

 

                             
     Millions of Dollars  
     September 30
2012
     December 31
2011
 
  

 

 

 

Crude oil and petroleum products

   $ 436        3,633  

Materials, supplies and other

     740        998  

 

 
   $ 1,176        4,631  

 

 

Inventories valued on the last-in, first-out (LIFO) basis totaled $332 million and $3,387 million at September 30, 2012, and December 31, 2011, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $100 million and $8,400 million at September 30, 2012, and December 31, 2011, respectively.

A significant portion of our inventories at December 31, 2011, was related to our Downstream business. See Note 2—Separation of Downstream Business, for additional information.

Note 5—Assets Held for Sale or Sold

In August 2012, we sold our 30 percent interest in Naryanmarneftegaz (NMNG) and certain related assets and recognized a gain of $206 million before-tax, which was included in the “Gain (loss) on dispositions” line on our consolidated income statement. At the time of the disposition, the carrying value of our equity investment in NMNG, which was included in our Other International segment, was $244 million.

Note 6—Investments, Loans and Long-Term Receivables

APLNG

In January 2012, APLNG and Sinopec signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million tonnes of LNG per year through 2035. This agreement, in combination with the execution of an LNG sale and purchase agreement with The Kansai Electric Power Co. Inc., in June 2012 for approximately 1.0 million tonnes of LNG per year through 2035, finalized the marketing of the second train.

In July 2012, we sanctioned the development of the second 4.5-million-tonnes-per-year LNG production train for our APLNG coal seam gas to LNG project. LNG exports from the second train are expected to commence in early 2016 under binding sales agreements to Sinopec and Kansai. Upon sanctioning of the second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed to additional shares in APLNG, which increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin’s ownership interest diluted from 42.5 percent to 37.5 percent. We recorded a before- and after-tax loss of $133 million from the dilution in the third quarter of 2012. The book value of our investment in APLNG was reduced by $453 million, and we reduced the foreign currency translation adjustment associated with our investment by $320 million. As of September 30, 2012, the book value of our equity method investment in APLNG was $10,444 million, which included $3,438 million of cumulative translation effects due to a strengthening Australian dollar relative to the U.S. Dollar, and is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

In addition, APLNG executed project financing agreements for an $8.5 billion project finance facility during the third quarter of 2012. The $8.5 billion project finance facility is composed of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $2.9 billion,

 

10


Table of Contents

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 12—Guarantees, for additional information.

As of the third quarter of 2012, 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 3—Variable Interest Entities (VIEs) for additional information.

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, 2012, included the following:

 

   

$579 million in loan financing to Freeport LNG.

 

   

$1,092 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.”

Long-term receivables from non-affiliated companies are included in the “Investments and long-term receivables” line on our consolidated balance sheet, while the short-term portion related to non-affiliate loans is in “Accounts and notes receivable.”

Note 7—Suspended Wells

The capitalized cost of suspended wells at September 30, 2012, was $1,013 million, a decrease of $24 million from $1,037 million at year-end 2011. No suspended wells were charged to dry hole expense during the first nine months of 2012 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2011.

Note 8—Impairments

During the three- and nine-month periods of 2012 and 2011, we recognized before-tax impairment charges within the following segments:

 

                                                           
     Millions of Dollars  
     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2012      2011      2012      2011  
  

 

 

    

 

 

 

Canada

   $                 213          

Europe

                     79          

Asia Pacific and Middle East

                     4          

 

 
   $                 296          

 

 

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

 

11


Table of Contents

“Exploration expenses” line on our consolidated income statement. In addition, the nine-month period of 2012 included a $78 million impairment in our Europe segment, primarily due to an increase in the asset retirement obligation for the Don Field in the United Kingdom, which has ceased production. See Note 20—Segment Disclosures and Related Information, for additional information on our segments.

Note 9—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 commercial paper program, which is used to fund commitments relating to the QG3 Project. Commercial paper maturities are generally limited to 90 days.

At both September 30, 2012, and December 31, 2011, we had no direct outstanding borrowings under our revolving credit facilities, with no letters of credit issued as of September 30, 2012, and $40 million as of December 31, 2011. In addition, under the two commercial paper programs, there was $1,540 million of commercial paper outstanding at September 30, 2012, compared with $1,128 million at December 31, 2011. Since we had $1,540 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facilities at September 30, 2012.

At September 30, 2012, we classified $967 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 2012, the following debt instruments were repaid prior to their maturity:

 

   

The $400 million 4.4% Notes due 2013.

 

   

$1,100 million of the $1,500 million 4.75% Notes due 2014.

We incurred a before-tax loss on redemption of $79 million, consisting of a make-whole premium and unamortized issuance costs.

Note 10—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 $763 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2012, consolidated balance sheet. The principal portion of these payments, which totaled $546 million in the first nine months of 2012, 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.

 

12


Table of Contents

Note 11—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first nine months of 2012 and 2011 was as follows:

 

                                                                                         
     Millions of Dollars  
     2012     2011  
    

Common

Stockholders’

Equity

   

Non-

Controlling

Interest

   

Total

Equity

   

Common  

Stockholders’  

Equity*

    

Non-

Controlling

Interest

   

Total  

Equity*

 
  

 

 

   

 

 

 

Balance at January 1

   $ 65,239       510       65,749       68,577           547       69,124     

Net income

     7,002       55       7,057       9,046           46       9,092     

Dividends

     (2,469            (2,469     (2,761)                (2,761)   

Repurchase of company common stock

     (5,098            (5,098     (7,984)                (7,984)   

Distributions to noncontrolling interests

            (63     (63     —           (70     (70)   

Separation of Downstream business

     (18,623     (31     (18,654     —                  —     

Other changes, net**

     1,355              1,355       (1,057)         (3     (1,060)   

 

 

Balance at September 30

   $ 47,406       471       47,877       65,821           520       66,341     

 

 

  * Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income.

**Includes components of other comprehensive income, which are disclosed separately in the Consolidated Statement of Comprehensive Income.

Income from continuing operations and discontinued operations attributable to ConocoPhillips for the three- and nine-month periods of 2012 and 2011 were as follows:

 

                                                           
     Millions of Dollars  
     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2012      2011      2012      2011  
  

 

 

    

 

 

 

Income from continuing operations

   $ 1,797        1,482        5,755        6,070  

Income from discontinued operations

     1        1,134        1,247        2,976  

 

 

Net Income

   $ 1,798        2,616        7,002        9,046  

 

 

Note 12—Guarantees

At September 30, 2012, 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.

 

13


Table of Contents

APLNG Guarantees

At September 30, 2012, 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 2012 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. Our maximum potential amount of future payments related to this guarantee is approximately $120 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 milestones, which we estimate would occur beginning in 2016. Our maximum exposure at September 30, 2012, is zero based upon our pro-rata share of the facility used at that date. In connection with issuance of the guarantee, we recorded a guarantee liability of $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 4 to 19 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1.1 billion ($2.6 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. Our maximum potential amount of future payments related to these guarantees is approximately $110 million and would become payable if APLNG does not perform.

Guarantees of Joint Venture Debt

At September 30, 2012, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 24 years. The maximum potential amount of future payments under the guarantees is approximately $70 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $380 million, which consist primarily of a guarantee to fund the short-term cash liquidity deficit of two joint ventures, a guarantee of minimum charter revenue for an LNG vessel, one small construction completion guarantee, guarantees of the lease payment obligations of a joint venture, guarantees of the residual value of leased corporate aircraft, and guarantees of the performance of a business partner or some of its customers. These guarantees generally extend up to 12 years or life of the venture.

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these 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

 

14


Table of Contents

maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at September 30, 2012, was approximately $70 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 were approximately $60 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 13—Contingencies and Commitments. “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet.

In connection with the separation of the Downstream business, the Company entered into an Indemnification and Release Agreement with Phillips 66. See Note 2—Separation of Downstream Business, for additional information. This agreement provides 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 13—Contingencies and Commitments

A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. 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. In the case of 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 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.

 

15


Table of Contents

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state 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 state agencies 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 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, 2012, our balance sheet included a total environmental accrual of $380 million, compared with $922 million at December 31, 2011. A significant portion of our environmental contingencies at December 31, 2011, was related to our Downstream business. See Note 2—Separation of Downstream Business, for additional information. 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, 2012, we had performance obligations secured by letters of credit of $837 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, services and items of permanent investment 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, in November 2007 we filed a request for international arbitration, 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. We are currently awaiting an interim decision on key legal and factual issues, which we anticipate receiving in the first half of 2013. In a separate commercial arbitration from the Company’s ICSID claim discussed above, on September 17, 2012, an International Chamber of Commerce

 

16


Table of Contents

arbitration tribunal issued a decision in favor of the Company finding PDVSA owes $67 million for pre-expropriation breaches of the Petrozuata project agreements.

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 ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally 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. An arbitration hearing on case merits occurred in March 2011, and we are awaiting a decision. On April 24, 2012, Ecuador filed a revised supplemental counterclaim asserting environmental damages, which we believe are not material. The arbitration process is ongoing.

Note 14—Derivative and Financial Instruments

Derivative Instruments

We use derivative instruments to manage our exposure to cash flow variability from commodity price risk. We occasionally use derivatives to capture market opportunities based on our industry knowledge. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids.

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 our 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.

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

 

                             
     Millions of Dollars  
     September 30
2012
     December 31
2011
 
  

 

 

 

Assets

     

Prepaid expenses and other current assets

   $ 2,429        4,433  

Other assets

     188        415  

Liabilities

     

Other accruals

     2,389        4,350  

Other liabilities and deferred credits

     189        374  

 

 

 

17


Table of Contents

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
 
     2012     2011     2012     2011  
  

 

 

   

 

 

 

Sales and other operating revenues

   $ (217     249       (357     198  

Other income

     3       (6     (2     (2

Purchased commodities

     184       (191     288       (129

 

 

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

 

                             
     Open Position
Long / (Short)
 
    

September 30

2012

   

December 31

2011

 
  

 

 

 

Commodity

    

Crude oil, refined products and natural gas liquids (millions of barrels)

            (13

Natural gas and power (billions of cubic feet equivalent)

    

Fixed price

     (64     (57

Basis

     97       (25

 

 

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.

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

 

                             
     Millions of Dollars  
    

September 30

2012

    

December 31

2011

 
  

 

 

 

Assets

     

Prepaid expenses and other current assets

   $ 72        12  

Other assets

             1  

Liabilities

     

Other accruals

     16        23  

Other liabilities and deferred credits

     1          

 

 

 

18


Table of Contents

The (gains) losses from foreign currency exchange 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
 
     2012     2011     2012     2011  
  

 

 

   

 

 

 

Foreign currency transaction (gains) losses

   $ (39     (11     (129     (15

 

 

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

 

                                            
     In Millions
Notional Currency (1)
 
    

September 30

2012

    

December 31

2011

 
  

 

 

 

Sell U.S. dollar, buy other currencies (2)

     USD         285        1,949  

Sell euro, buy other currencies (3)

     EUR                 61  

Buy U.S. dollar, sell other currencies (4)

     USD         477          

Buy British pound, sell other currencies (5)

     GBP         3,709          

Buy euro, sell British pound

     EUR         176          

 

 

(1) Denominated in U.S. dollars (USD), British pound (GBP) and euros (EUR).

(2) Primarily euro, Canadian dollar, Norwegian krone and British pound.

(3) Primarily Norwegian krone and British pound.

(4) Primarily Canadian dollar, euro and Norwegian krone.

(5) Primarily euro and U.S. dollar.

Financial Instruments

We have certain financial instruments on the consolidated balance sheet related to interest bearing time deposits and commercial paper. These held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included in “Short-term investments” on our consolidated balance sheet.

These balances consisted of the following:

 

                                                           
     Millions of Dollars  
     Carrying Amount  
     Cash and Cash Equivalents      Short-Term Investments  
    

September 30

2012

    

December 31

2011

    

September 30

2012

    

December 31

2011

 
  

 

 

    

 

 

 

Cash

   $ 636        1,169                  

Time Deposits

           

Remaining maturities from 1 to 90 days

     632        4,318                349  

Commercial Paper

           

Remaining maturities from 1 to 90 days

             293                232  

 

 
   $ 1,268        5,780                581  

 

 

 

19


Table of Contents

In conjunction with the separation of our Downstream business, we received a special cash distribution from Phillips 66 of $7,818 million. See Note 2—Separation of Downstream Business, for additional information. At September 30, 2012, the unused amount of the special cash distribution was $2,468 million and is designated as “Restricted cash” on our consolidated balance sheet. At September 30, 2012, the funds in the restricted cash account were invested in U.S. Treasury Bills ($268 million) and money market funds ($2,200 million) with maturities within 90 days from September 30, 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 and short-term investments 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 or letters of credit 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 and performance 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.

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on September 30, 2012, and December 31, 2011, was $142 million and $237 million, respectively. No collateral was posted for September 30, 2012, and $3 million was posted for December 31, 2011. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on September 30, 2012, 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 $142 million of additional collateral, either with cash or letters of credit.

 

20


Table of Contents

Note 15—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 that 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. 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 derivative instruments 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. As reflected in the table below, 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, 2012      December 31, 2011  
     Level 1      Level 2      Level 3      Total      Level 1      Level 2      Level 3      Total  
  

 

 

    

 

 

 

Assets

                       

Deferred compensation investments

   $ 309                        309        336                        336  

Commodity derivatives

     1,788        803        18        2,609        2,807        1,947        72        4,826  

 

 

Total assets

   $ 2,097        803        18        2,918        3,143        1,947        72        5,162  

 

 

Liabilities

                       

Commodity derivatives

   $ 1,749        814        7        2,570        2,970        1,722        10        4,702  

 

 

Total liabilities

   $ 1,749        814        7        2,570        2,970        1,722        10        4,702  

 

 

Non-Recurring Fair Value Measurement

There were no significant non-recurring fair value measurements as of September 30, 2012.

 

21


Table of Contents

Reported Fair Value of Financial Instruments

The following are the valuation techniques and methods used to estimate the fair value of financial assets and liabilities reported on the balance sheet:

 

   

Cash and cash equivalents, restricted cash and short-term investments: 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 6—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 reported in accounts payable 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, discounted at September 30, 2012, and December 31, 2011, effective yield rates of 0.76 percent and 1.24 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 10—Joint Venture Acquisition Obligation, for additional information.

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

2012

    

December 31

2011

    

September 30

2012

    

December 31

2011

 
  

 

 

    

 

 

 

Financial assets

           

Deferred compensation investments

   $ 309        336        309        336  

Commodity derivatives

     295        814        295        814  

Total loans and advances—related parties

     1,710        1,793        1,914        1,994  

Financial liabilities

           

Total debt, excluding capital leases

     21,100        22,592        26,012        27,065  

Total joint venture acquisition obligation

     3,769        4,314        4,192        4,820  

Commodity derivatives

     237        446        237        446  

 

 

At September 30, 2012, commodity derivative assets and liabilities appear net of $31 million of obligations to return cash collateral and $50 million of rights to reclaim cash collateral, respectively. At December 31, 2011, commodity derivative assets and liabilities appear net of no obligations to return cash collateral and $244 million of rights to reclaim cash collateral.

 

22


Table of Contents

Note 16—Accumulated Other Comprehensive Income

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

 

                                                                          
     Millions of Dollars  
    

Defined

Benefit Plans

   

Net

Unrealized

Gain on

Securities

    

Foreign

Currency

Translation

    Hedging    

Accumulated

Other

Comprehensive

Income

 
  

 

 

 

December 31, 2011*

   $ (1,971             5,223       (6     3,246  

Other comprehensive income (loss)

     (74     1        946       6       879  

Separation of Downstream business

     683               (469            214  

 

 

September 30, 2012

   $ (1,362     1        5,700              4,339  

 

 

* The beginning balance of retained earnings has been restated primarily to reflect certain intercompany loans as permanently invested in 2004 and prior periods, which resulted in a $160 million increase in Foreign Currency Translation and Accumulated Other Comprehensive Income, a $15 million decrease to Total Liabilities, and a $145 million reduction in Retained Earnings. The impact on net income and earnings per share was de minimis for the three- and nine-month periods ended September 30, 2012 and 2011.

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

Note 17—Cash Flow Information

 

                             
     Millions of Dollars  
     Nine Months Ended
September  30
 
     2012     2011  
  

 

 

 

Cash Payments

    

Interest

   $ 596       739  

Income taxes

     6,394       7,145  

 

 

Net Sales (Purchases) of Short-Term Investments

    

Short-term investments purchased

   $ (497     (6,642

Short-term investments sold

     1,094       5,019  

 

 
   $ 597       (1,623

 

 

Note 18—Employee Benefit Plans

In connection with the separation of the Downstream business, ConocoPhillips entered into an Employee Matters Agreement with Phillips 66 (see Note 2—Separation of Downstream Business), which provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by ConocoPhillips. Upon separation, the ConocoPhillips Pension Plan transferred assets and obligations to the Phillips 66 Pension Plan resulting in a net decrease in sponsored pension plan obligations of $1,127 million. Additionally, as a result of the transfer of unrecognized losses to Phillips 66, deferred income taxes and other comprehensive income decreased $335 million and $570 million, respectively.

 

23


Table of Contents

Pension and Postretirement Plans

 

                                                                                         
     Millions of Dollars  
     Pension Benefits     Other Benefits  
     2012     2011     2012     2011  
  

 

 

   

 

 

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

 

 

   

 

 

     

Components of Net Periodic Benefit Cost

            

Three Months Ended September 30

            

Service cost

   $ 33       20       56       25       1       3  

Interest cost

     39       35       62       45       8       10  

Expected return on plan assets

     (47     (37     (70     (44              

Amortization of prior service cost

     1       (2     2              (1     (1

Recognized net actuarial (gain) loss

     41       13       42       11              (1

 

 

Net periodic benefit costs

   $ 67       29       92       37       8       11  

 

 

Nine Months Ended September 30

            

Service cost

   $ 133       70       169       74       5       8  

Interest cost

     150       116       185       133       26       31  

Expected return on plan assets

     (177     (120     (210     (131              

Amortization of prior service cost

     5       (6     7              (3     (5

Recognized net actuarial (gain) loss

     145       46       124       34       (1     (4

 

 

Net periodic benefit costs

   $ 256       106       275       110       27       30  

 

 

During the first nine months of 2012, we contributed $258 million to our domestic benefit plans and $161 million to our international benefit plans. In 2012, we expect to contribute approximately $410 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $210 million to our international qualified and nonqualified pension and postretirement benefit plans.

During the three months ended September 30, 2012, it became probable 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. The increase in the liability was primarily due to a reduction of the discount rate used to determine benefit obligations from 4.30% at December 31, 2011 to 3.35% at the measurement date. The assumptions used for rate of compensation increased from 4.25% to 4.75% over the same time period.

In addition, pursuant to the Employee Matters Agreement we made certain adjustments to the exercise price and number of our stock-based compensation awards with the intention of preserving the intrinsic value of the awards prior to the separation. Outstanding options to purchase common shares of ConocoPhillips stock that were exercisable prior to the separation were adjusted so the holders of those options would then hold options to purchase common shares of both ConocoPhillips and Phillips 66 stock. Non-exercisable stock options were converted to those of the entity where the employee is working post-separation. In addition, former employee holders and a specified group of holders of stock options and restricted stock units who retired or terminated employment upon or shortly after the separation, received both adjusted ConocoPhillips awards and Phillips 66 awards. ConocoPhillips restricted stock and performance share units awarded for completed performance periods under the Performance Share Program, as well as restricted stock units held by current or former directors, were adjusted to provide holders one restricted share or restricted stock unit of Phillips 66 for every two restricted shares or restricted stock units of ConocoPhillips. Each employee holder of restricted stock and restricted stock units awarded under all other programs were adjusted to provide holders restricted shares or restricted stock units in the company that employs such employee following the separation. Adjustments to our stock-based compensation awards did not have a material impact on compensation expense.

 

 

24


Table of Contents

Note 19—Related Party Transactions

Significant transactions with related parties were:

 

                                                           
     Millions of Dollars  
     Three Months Ended
September 30
     Nine Months Ended
September  30
 
     2012      2011      2012      2011  
  

 

 

    

 

 

 

Operating revenues and other income

   $ 9        11        42        38  

Purchases

     37        44        121        287  

Operating expenses and selling, general and administrative expenses

     52        57        133        190  

Net interest expense*

     8        15        30        47  

 

 

* We paid and/or received interest to/from various affiliates, including FCCL Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 20—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, and has been reported as discontinued operations in all periods presented. Our reportable segments changed upon separation, and, as a result, all prior periods presented have been restated. 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 2—Separation of Downstream Business.

Our LUKOIL Investment represents our prior investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011.

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

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

 

25


Table of Contents

Analysis of Results by Operating Segment

 

                                                           
     Millions of Dollars  
     Three Months Ended
September 30
    Nine Months Ended
September 30
 
     2012     2011     2012     2011  
  

 

 

   

 

 

   

 

 

   

 

 

 

Sales and Other Operating Revenues

        

Alaska

   $ 2,005       2,363       7,135       7,280  

 

 

Lower 48 and Latin America

     4,807       6,296       14,110       17,921  

Intersegment eliminations

     (40     (63     (196     (227

 

 

Lower 48 and Latin America

     4,767       6,233       13,914       17,694  

 

 

Canada

     1,288       1,595       3,580       4,681  

Intersegment eliminations

     (117     (230     (330     (758

 

 

Canada

     1,171       1,365       3,250       3,923  

 

 

Europe

     3,285       3,915       10,813       12,294  

Intersegment eliminations

                   (72     (50

 

 

Europe

     3,285       3,915       10,741       12,244  

 

 

Asia Pacific and Middle East

     2,167       2,151       5,697       6,730  

Intersegment eliminations

     (41     (1     (41     (1

 

 

Asia Pacific and Middle East

     2,126       2,150       5,656       6,729  

 

 

Other International

     1,067       399       2,663       1,442  

LUKOIL Investment

                            

Corporate and Other

     99       81       133       150  

 

 

Consolidated sales and other operating revenues

   $ 14,520       16,506       43,492       49,462  

 

 

Net Income Attributable to ConocoPhillips

        

Alaska

   $ 535       502       1,706       1,558  

Lower 48 and Latin America

     182       334       556       996  

Canada

     (31     73       (674     201  

Europe

     132       266       1,190       1,265  

Asia Pacific and Middle East

     669       469       3,179       2,288  

Other International

     567       53       634       251  

LUKOIL Investment

                          239  

Corporate and Other

     (257     (215     (836     (728

Discontinued operations

     1       1,134       1,247       2,976  

 

 

Consolidated net income attributable to ConocoPhillips

   $ 1,798       2,616       7,002       9,046  

 

 

 

                             
     Millions of Dollars  
    

September 30

2012

    

December 31

2011

 
  

 

 

 

Total Assets

     

Alaska

   $ 11,062        10,723  

Lower 48 and Latin America

     28,444        25,872  

Canada

     22,075        20,847  

Europe

     14,305        12,452  

Asia Pacific and Middle East

     23,532        22,374  

Other International

     9,741        9,070  

LUKOIL Investment

               

Corporate and Other

     6,210        8,485  

Discontinued operations

             43,407  

 

 

Consolidated total assets

   $ 115,369        153,230  

 

 

 

26


Table of Contents

Note 21—Income Taxes

Our effective tax rate from continuing operations for the third quarter of 2012 was 52 percent compared with 59 percent for the third quarter of 2011. The lower rate was due primarily to tax benefits associated with asset dispositions occurring in 2012, partially offset by higher income in higher tax rate jurisdictions in 2012.

Our effective tax rate from continuing operations for the first nine months of 2012 was 53 percent compared with 52 percent for the first nine months of 2011.

For both the third quarter and the first nine months of 2012, the effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

In the United Kingdom, legislation was enacted on July 17, 2012, restricting corporate tax relief on decommissioning costs to 50 percent, retroactively effective from March 21, 2012. Our third quarter 2012 earnings were reduced by $170 million due to the remeasurement of deferred tax balances as of the effective date.

 

27


Table of Contents

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.

 

28


Table of Contents
                                                                                                                       
     Millions of Dollars  
     Three Months Ended September 30, 2012  
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

   $        4,029                             10,491              14,520  

Equity in earnings of affiliates

     2,169       2,555                             327       (4,642     409  

Gain on dispositions

            3                             115              118  

Other income (loss)

     (78     100                             20              42  

Intercompany revenues

     21       94       11        22       8       752       (908       

 

 

Total Revenues and Other Income

     2,112       6,781       11        22       8       11,705       (5,550     15,089  

 

 

Costs and Expenses

                 

Purchased commodities

            3,470                             3,338       (372     6,436  

Production and operating expenses

            313                             1,400       (2     1,711  

Selling, general and administrative expenses

     2       260                             68              330  

Exploration expenses

            101                             118              219  

Depreciation, depletion and amortization

            197                             1,502              1,699  

Taxes other than income taxes

            57                             619              676  

Accretion on discounted liabilities

            13                             89              102  

Interest and debt expense

     542       76       10        19       8       40       (534     161  

Foreign currency transaction (gains) losses

     (28     (7             46       46       (58            (1

 

 

Total Costs and Expenses

     516       4,480       10        65       54       7,116       (908     11,333  

 

 

Income (loss) from continuing operations before income taxes

     1,596       2,301       1        (43     (46     4,589       (4,642     3,756  

Provision for income taxes

     (200     132               1       (6     2,018              1,945  

 

 

Income (Loss) From Continuing Operations

     1,796       2,169       1        (44     (40     2,571       (4,642     1,811  

Income from discontinued operations

     2       2                             2       (4     2  

 

 

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  

 

 
Income Statement    Three Months Ended September 30, 2011  

Revenues and Other Income

                 

Sales and other operating revenues

   $        5,585                             10,921              16,506  

Equity in earnings of affiliates

     1,759       1,914                             638       (3,868     443  

Gain (loss) on dispositions

            (2                           (258            (260

Other income (loss)

     (1     (23                           30              6  

Intercompany revenues

     1       191       11        23       9       834       (1,069       

 

 

Total Revenues and Other Income

     1,759       7,665       11        23       9       12,165       (4,937     16,695  

 

 

Costs and Expenses

                 

Purchased commodities

            4,857                             3,729       (610     7,976  

Production and operating expenses

            293                             1,479       (5     1,767  

Selling, general and administrative expenses

     2       88                             56       (1     145  

Exploration expenses

            99                             167              266  

Depreciation, depletion and amortization

            216                             1,429              1,645  

Taxes other than income taxes

            66                             838              904  

Accretion on discounted liabilities

            12                             95              107  

Interest and debt expense

     427       106       10        19       8       113       (453     230  

Foreign currency transaction (gains) losses

            8               (106     (101     249              50  

 

 

Total Costs and Expenses

     429       5,745       10        (87     (93     8,155       (1,069     13,090  

 

 

Income from continuing operations before income taxes

     1,330       1,920       1        110       102       4,010       (3,868     3,605  

Provision for income taxes

     (150     161               2       16       2,081              2,110  

 

 

Income From Continuing Operations

     1,480       1,759       1        108       86       1,929       (3,868     1,495  

Income from discontinued operations

     1,136       1,136                             750       (1,886     1,136  

 

 

Net income

     2,616       2,895       1        108       86       2,679       (5,754     2,631  

Less: net income (loss) attributable to noncontrolling interests

                                         (15            (15

 

 

Net Income Attributable to ConocoPhillips

   $ 2,616       2,895       1        108       86       2,664       (5,754     2,616  

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

   $ (306     (27     1        (3     42       (277     264       (306

 

 

 

29


Table of Contents
                                                                                                                       
     Millions of Dollars  
     Nine Months Ended September 30, 2012  
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

   $        12,598                             30,894              43,492  

Equity in earnings of affiliates

     6,848       7,785                             1,355       (14,564     1,424  

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

     6,811       21,320       34        67       25       37,169       (18,701     46,725  

 

 

Costs and Expenses

                 

Purchased commodities

            11,044                             9,642       (2,372     18,314  

Production and operating expenses

            917                             4,336       (21     5,232  

Selling, general and administrative expenses

     10       690                             201       (9     892  

Exploration expenses

            287                             881              1,168  

Depreciation, depletion and amortization

            605                             4,343              4,948  

Impairments

                                         296              296  

Taxes other than income taxes

            207                             2,476              2,683  

Accretion on discounted liabilities

            39                             275              314  

Interest and debt expense

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

Foreign currency transaction (gains) losses

     (30     19               34       47       (52            18  

 

 

Total Costs and Expenses

     1,648       14,055       31        92       71       22,653       (4,137     34,413  

 

 

Income (loss) from continuing operations before income taxes

     5,163       7,265       3        (25     (46     14,516       (14,564     12,312  

Provision for income taxes

     (589     417       1        7       (6     6,675              6,505  

 

 

Income (Loss) From Continuing Operations

     5,752       6,848       2        (32     (40     7,841       (14,564     5,807  

Income from discontinued operations

     1,250       1,250                             997       (2,247     1,250  

 

 

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  

 

 
Income Statement    Nine Months Ended September 30, 2011  

Revenues and Other Income

                 

Sales and other operating revenues

   $        15,904                             33,558              49,462  

Equity in earnings of affiliates

     6,793       6,722                             1,277       (13,648     1,144  

Gain on dispositions

            263                             125              388  

Other income (loss)

     (1     46                             127              172  

Intercompany revenues

     3       1,072       34        69       26       2,000       (3,204       

 

 

Total Revenues and Other Income

     6,795       24,007       34        69       26       37,087       (16,852     51,166  

 

 

Costs and Expenses

                 

Purchased commodities

            13,927                             10,622       (1,934     22,615  

Production and operating expenses

            855                             4,145       (59     4,941  

Selling, general and administrative expenses

     11       405                             189       (9     596  

Exploration expenses

            225                             481              706  

Depreciation, depletion and amortization

            660                             4,679              5,339  

Taxes other than income taxes

            226                             2,760              2,986  

Accretion on discounted liabilities

            35                             284              319  

Interest and debt expense

     1,109       343       31        58       24       366       (1,202     729  

Foreign currency transaction (gains) losses

            (8             (50     (93     226              75  

 

 

Total Costs and Expenses

     1,120       16,668       31        8       (69     23,752       (3,204     38,306  

 

 

Income from continuing operations before income taxes

     5,675       7,339       3        61       95       13,335       (13,648     12,860  

Provision for income taxes

     (391     546       1        1       24       6,567              6,748  

 

 

Income From Continuing Operations

     6,066       6,793       2        60       71       6,768       (13,648     6,112  

Income from discontinued operations

     2,980       2,980                             2,149       (5,129     2,980  

 

 

Net income

     9,046       9,773       2        60       71       8,917       (18,777     9,092  

Less: net income attributable to noncontrolling interests

                                         (46            (46

 

 

Net Income Attributable to ConocoPhillips

   $ 9,046       9,773       2        60       71       8,871       (18,777     9,046  

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

   $ 7,476       8,203       2        (2     46       7,189       (15,438     7,476  

 

 

 

30


Table of Contents
                                                                                                                       
     Millions of Dollars  
     September 30, 2012  
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

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

Restricted cash

     2,468                                                    2,468  

Accounts and notes receivable

     20       6,905                              12,619        (10,361     9,183  

Inventories

            167                              1,009               1,176  

Prepaid expenses and other current assets

     19       728                1              938               1,686  

 

 

Total Current Assets

     2,508       7,812        3        45       1       15,773        (10,361     15,781  

Investments, loans and long-term receivables*

     79,733       115,262        771        1,496       595       40,667        (213,460     25,064  

Net properties, plants and equipment

            8,519                              65,093               73,612  

Intangibles

            8                              2               10  

Other assets

     57       204                2       3       636               902  

 

 

Total Assets

   $ 82,298       131,805        774        1,543       599       122,171        (223,821     115,369  

 

 

Liabilities and Stockholders’ Equity

                   

Accounts payable

   $        14,605                3       1       5,734        (10,361     9,982  

Short-term debt

     1,378       4        750                      203               2,335  

Accrued income and other taxes

            129                4              2,704               2,837  

Employee benefit obligations

            470                              208               678  

Other accruals

     139       210        19        32       11       1,140               1,551  

 

 

Total Current Liabilities

     1,517       15,418        769        39       12       9,989        (10,361     17,383  

Long-term debt

     9,454       3,220                1,250       499       4,359               18,782  

Asset retirement obligations and accrued environmental costs

            1,168                              7,253               8,421  

Joint venture acquisition obligation

                                          3,006               3,006  

Deferred income taxes

     14       58                16       3       14,064               14,155  

Employee benefit obligations

            2,523                              699               3,222  

Other liabilities and deferred credits*

     30,454       19,991                139       77       17,274        (65,412     2,523  

 

 

Total Liabilities

     41,439       42,378        769        1,444       591       56,644        (75,773     67,492  

Retained earnings

     28,242       22,341        3        (102     (95     31,549        (47,174     34,764  

Other common stockholders’ equity

     12,617       67,086        2        201       103       33,507        (100,874     12,642  

Noncontrolling interests

                                          471               471  

 

 

Total Liabilities and Stockholders’ Equity

   $ 82,298       131,805        774        1,543       599       122,171        (223,821     115,369  

 

 
Balance Sheet    December 31, 2011**  

Assets

                   

Cash and cash equivalents

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

Short-term investments

                                          581               581  

Accounts and notes receivable

     60       9,186                              20,898        (13,618     16,526  

Inventories

            2,239                              2,392               4,631  

Prepaid expenses and other current assets

     22       1,090                1              1,587               2,700  

 

 

Total Current Assets

     82       14,543        1        38       1       29,171        (13,618     30,218  

Investments, loans and long-term receivables*

     96,284       135,618        760        1,417       565       59,651        (260,512     33,783  

Net properties, plants and equipment

            19,595                              64,585               84,180  

Goodwill

            3,332                                             3,332  

Intangibles

            722                              23               745  

Other assets

     64       301                2       3       602               972  

 

 

Total Assets

   $ 96,430       174,111        761        1,457       569       154,032        (274,130     153,230  

 

 

Liabilities and Stockholders’ Equity

                   

Accounts payable

   $ 10       18,747                1       1       14,512        (13,618     19,653  

Short-term debt

     892       27                              94               1,013  

Accrued income and other taxes

            315                2              3,903               4,220  

Employee benefit obligations

            835                              276               1,111  

Other accruals

     244       634        9        14       6       1,164               2,071  

 

 

Total Current Liabilities

     1,146       20,558        9        17       7       19,949        (13,618     28,068  

Long-term debt

     10,951       3,599        749        1,250       498       4,563               21,610  

Asset retirement obligations and accrued environmental costs

            1,766                              7,563               9,329  

Joint venture acquisition obligation

                                          3,582               3,582  

Deferred income taxes

     (5     3,982                11       9       14,043               18,040  

Employee benefit obligations

            3,092                              976               4,068  

Other liabilities and deferred credits*

     25,959       40,479                104       29       20,047        (83,834     2,784  

 

 

Total Liabilities

     38,051       73,476        758        1,382       543       70,723        (97,452     87,481  

Retained earnings

     42,550       34,921        1        (70     (55     29,821        (58,119     49,049  

Other common stockholders’ equity

     15,829       65,714        2        145       81       52,978        (118,559     16,190  

Noncontrolling interests

                                          510               510  

 

 

Total Liabilities and Stockholders’ Equity

   $ 96,430       174,111        761        1,457       569       154,032        (274,130     153,230  

 

 
  *Includes intercompany loans.   
**Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.    

 

31


Table of Contents

 

                                                                                                                       
     Millions of Dollars  
     Nine Months Ended September 30, 2012  
Statement of Cash Flows    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 continuing operating activities

   $ 3,530       12,353       2        7              4,423       (10,469     9,846  

Net cash provided by (used in) discontinued operations

            397                             (191            206  

 

 

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                           (10,147     4,685       (11,337

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                           (2,900     2,955       (19

Collection of advances/loans—related parties

            133                             1,092       (1,125     100  

Other

            4                             173              177  

 

 

Net cash used in continuing investing activities

     (303     (4,562                           (9,099     5,570       (8,394

Net cash provided by (used in) discontinued operations

            (232                           8,028       (8,100     (304

 

 

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                                  (5,011     5,011       (2,469

Other

     (1     63                             (1,540     931       (547

 

 

Net cash used in continuing financing activities

     (3,226     (6,178                           (6,673     12,213       (3,864

Net cash provided by (used in) discontinued operations operations

            (3,786                           981       786       (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  

 

 
Statement of Cash Flows    Nine Months Ended September 30, 2011  

Cash Flows From Operating Activities

                 

Net cash provided by (used in) continuing

                 

operating activities

   $ 10,645       (3,087     2        6       (6     7,113       (3,277     11,396  

Net cash provided by (used in) discontinued operations

            (181                           2,619              2,438  

 

 

Net Cash Provided by (Used in) Operating Activities

     10,645       (3,268     2        6       (6     9,732       (3,277     13,834  

 

 

Cash Flows From Investing Activities

                 

Capital expenditures and investments

            (1,092                           (7,653     (2     (8,747

Proceeds from asset dispositions

            318                             1,636              1,954  

Net purchases of short-term investments

                                         (1,623            (1,623

Long-term advances/loans—related parties

            (113             (4            (4,562     4,665       (14

Collection of advances/loans—related parties

     (1     622                             1,504       (2,037     88  

Other

            5                             32       2       39  

 

 

Net cash used in continuing investing activities

     (1     (260             (4            (10,666     2,628       (8,303

Net cash provided by (used in) discontinued operations

            191                             (27            164  

 

 

Net Cash Used in Investing Activities

     (1     (69             (4            (10,693     2,628       (8,139

 

 

Cash Flows From Financing Activities

                 

Issuance of debt

            4,558                      4       19       (4,581       

Repayment of debt

            (1,807                           (564     1,952       (419

Issuance of company common stock

     109                                                  109  

Repurchase of company common stock

     (7,984                                                (7,984

Dividends paid

     (2,761                                  (2,573     2,573       (2,761

Other

     (8     54                             (588            (542

 

 

Net cash provided by (used in) continuing financing activities

     (10,644     2,805                      4       (3,706     (56     (11,597

Net cash used in discontinued operations

            (14                           (291     284       (21

 

 

Net Cash Provided by (Used in) Financing Activities

     (10,644     2,791                      4       (3,997     228       (11,618

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

            (10                           (84            (94

 

 

Net Change in Cash and Cash Equivalents

            (556     2        2       (2     (5,042     (421     (6,017

Cash and cash equivalents at beginning of period

            718               29       4       8,703              9,454  

 

 

Cash and Cash Equivalents at End of Period

   $        162       2        31       2       3,661       (421     3,437  

 

 

 

 

32


Table of Contents
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 53.

Due to the separation of our downstream businesses on April 30, 2012, which is reported as discontinued operations, income (loss) from continuing operations is more representative of ConocoPhillips as an independent exploration and production company. 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 proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have operations and activities in 30 countries. At September 30, 2012, we had approximately 16,700 employees worldwide and total assets of $115 billion.

The Separation

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, were transferred to Phillips 66. Results of operations related to Phillips 66 have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 2—Separation of Downstream Business, in the Notes to Consolidated Financial Statements.

Business Environment

As a newly established, independent E&P company, we are solely focused on exploring for, developing and producing oil and natural gas globally. Our commitment to safety and environmental stewardship, operating excellence and financial responsibility is fundamental to our success. We continue to focus on improving our financial position and increasing shareholder returns through production and margin growth, portfolio optimization and maintaining sector-leading dividend distributions. In order to remain competitive, we must continually develop and replenish a portfolio of projects which offer attractive financial returns on our investment. We continue to evaluate our assets regularly to determine whether they fit our strategic plans or should be sold or otherwise disposed, and, as a result, we remain positioned to complete our $8–$10 billion asset disposition program by the end of 2013. For the first nine months of 2012, we have generated proceeds of approximately $2.1 billion as part of this program, which mainly included the sale of the Vietnam business, the Alba and Statfjord fields in the North Sea and our investment in Naryanmarneftegaz (NMNG) in Russia.

 

33


Table of Contents

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 and maintain existing fields. In the short-term, we will fund a portion of our capital program through the proceeds from our strategic asset dispositions. In the long-term, we plan to fund our capital program organically by investing in high-return developments which will grow our margins and cash flow. We expect our capital spending will be $15.5 billion to $16 billion in 2012. Over the next five years, we plan to execute a disciplined capital program in order to generate 3 to 5 percent annual production volume and margin growth, primarily from major developments underway in the United States, Canada, the United Kingdom and Norwegian North Sea, Malaysia and Australia.

The most significant factors impacting our profitability and related reinvestment of our operating cash flows into our business are the prices for crude oil and natural gas. The prices for these commodity products are subject to factors external to our company, over which we have no control. These prices are supply- and demand-based and can be very volatile; therefore, our strategy is to maintain a core portfolio of low-risk, high-return projects from legacy assets, coupled with a portfolio which offers growth opportunities, such as unconventional plays, deepwater and arctic drilling and liquefied natural gas (LNG).

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
 
     2012      2011      2012      2011  
  

 

 

 

Market Indicators

           

WTI (per barrel)

   $ 92.11        89.70        96.18        95.37  

Dated Brent (per barrel)

     109.61        113.46        112.09        111.93  

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

     2.80        4.20        2.58        4.21  

 

 

Industry crude prices for WTI increased 3 percent in the third quarter of 2012 and increased 1 percent in the first nine months of 2012, compared with the same periods of 2011, while Brent prices decreased 3 percent in the third quarter of 2012 and remained relatively flat in the first nine months of 2012. Global oil prices strengthened during the third quarter of 2012, as global economic concerns eased and geopolitical risks remained high. WTI continued to trade at a discount to Brent, mainly due to high inventory levels and excess crude supply in the U.S. Midcontinent market.

Henry Hub natural gas prices decreased 33 percent in the third quarter of 2012, and decreased 39 percent in the first nine months of 2012, compared with the same periods of 2011. U.S. natural gas prices remained depressed in 2012, due to high inventory levels, which resulted from a warmer-than-normal winter and sustained production from shale plays. Prolonged low U.S. natural gas prices may continue to have an adverse effect on our results of operations. 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 26 percent in the first nine months of 2012, compared with the same period of 2011.

 

34


Table of Contents

Key Operating and Financial Highlights

Significant highlights during the third quarter of 2012 included the following:

 

   

Achieved quarterly production of 1.525 million barrels of oil equivalent per day.

   

Continued ramp-up of production in Eagle Ford and Bakken.

   

Continued growth from Canadian oil sands; successful startup of Christina Lake Phase D.

   

Advanced major growth projects and drilling programs.

   

Completed turnarounds at major facilities worldwide, as planned.

   

Increased exploration activity in conventional and unconventional opportunities globally.

   

Completed sale of NMNG and dilution of interest in Australia Pacific LNG (APLNG).

Outlook

Production for the fourth quarter of 2012 is expected to be higher than the third quarter of 2012, reflecting completion of turnaround activity and ongoing ramp-up in major North American programs, most notably in the Eagle Ford and Canadian oil sands. Full-year 2012 production is estimated to be 1.57 million to 1.58 million barrels of oil equivalent per day. We anticipate continued progress on our major projects and drilling programs in the fourth quarter of 2012, including the evaluation of drilling results on several exploration prospects.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2012, is based on a comparison with the corresponding period of 2011.

Consolidated Results

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. Our LUKOIL Investment represents our prior investment in the ordinary shares of OAO LUKOIL, which was sold in the first quarter of 2011. Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, costs related to the separation and certain technology activities, net of licensing revenues.

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
 
     2012     2011     2012     2011  
  

 

 

   

 

 

 

Alaska

   $ 535       502       1,706       1,558  

Lower 48 and Latin America

     182       334       556       996  

Canada

     (31     73       (674 )      201  

Europe

     132       266       1,190       1,265  

Asia Pacific and Middle East

     683       482       3,231       2,330  

Other International

     567       53       634       251  

LUKOIL Investment

                          239  

Corporate and Other

     (257     (215     (836 )      (728

 

 

Income from continuing operations

   $ 1,811       1,495       5,807       6,112  

 

 

 

35


Table of Contents

Earnings for ConocoPhillips increased 21 percent in the third quarter of 2012, while earnings for the nine-month period ended September 30, 2012, decreased 5 percent. The improvement in the third quarter of 2012 primarily resulted from:

 

   

Higher gains from asset sales of $336 million after-tax, compared with losses of $267 million after-tax in the third quarter of 2011.

   

Lower production taxes, mainly as a result of lower production volumes.

These items were partially offset by:

 

   

Lower prices.

   

Lower production volumes.

   

Pension settlement expense of $82 million after-tax. For additional information, see Note 18—Employee Benefit Plans, in the Notes to Consolidated Financial Statements.

The decrease in earnings for the nine-month period of 2012 was primarily due to:

 

   

Significantly lower volumes, largely due to dispositions, reduced production in China and higher planned maintenance.

   

Higher impairments. Non-cash impairments for the nine-month period of 2012 totaled $550 million after-tax.

   

Lower natural gas and natural gas liquids prices.

   

The absence of earnings from LUKOIL due to the divestiture of our interest.

   

Higher operating and selling, general and administrative (SG&A) expenses, which included the pension settlement expense of $82 million after-tax and separation costs of $80 million after-tax.

These items were partially offset by:

 

   

Higher gains from asset sales of $1,557 million after-tax, compared with gains of $152 million after-tax in the comparative period of 2011.

   

Lower production taxes and depreciation, depletion and amortization (DD&A) expenses, mainly as a result of lower volumes.

   

Higher crude oil and LNG prices.

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

Income Statement Analysis

Sales and other operating revenues decreased 12 percent in both the third quarter and nine-month period of 2012, mainly due to lower crude oil, natural gas and LNG volumes and lower natural gas and natural gas liquids prices. Higher LNG and crude oil prices partly offset the decrease in the nine-month period of 2012.

Equity in earnings of affiliates for the nine-month period of 2012 increased 24 percent. The increase primarily resulted from:

 

   

Improved earnings from Qatar Liquefied Gas Company Limited (3) (QG3), primarily due to higher LNG prices and a $72 million tax-related adjustment, partly offset by lower volumes.

   

The absence of the $83 million before-tax write-off of our investment associated with the cancellation of the Denali gas pipeline project in the second quarter of 2011.

   

Higher earnings from FCCL Partnership, mainly as a result of new production from Christina Lake Phases C and D, partly offset by lower bitumen prices.

These increases in equity earnings were partially offset by lower earnings from NMNG, largely due to lower volumes.

 

36


Table of Contents

Gain on dispositions for the third quarter and nine-month period of 2012 increased $378 million and $1,253 million, respectively, compared with corresponding periods in 2011. Gains realized in the third quarter of 2012 were primarily due to the disposition of our equity investment in NMNG and the sale of our interest in Block 39 in Peru, which were partly offset by the loss on further dilution of our equity interest in APLNG from 42.5 percent to 37.5 percent. This is compared with a loss in the third quarter of 2011 as a result of the initial dilution of our equity interest in APLNG from 50 percent to 42.5 percent. Additional gains realized in the nine-month period of 2012 mainly resulted from the disposition of our Vietnam business and the Statfjord and Alba fields located in the North Sea, partially offset by the sale of certain E&P assets located in the Lower 48 and the remaining divestiture of our LUKOIL shares in the nine-month period of 2011.

Purchased commodities decreased 19 percent in both the third quarter and nine-month period of 2012, largely as a result of lower U.S. natural gas prices, partly offset by higher purchased volumes.

Production and operating expenses increased 6 percent in the nine-month period of 2012, mostly due to increased operating expenses in China and major turnaround expenses at our Bayu-Undan Field and Darwin LNG facility.

SG&A expenses increased 128 percent and 50 percent in the third quarter and nine-month period of 2012, respectively, mainly as a result of the pension settlement expense. The nine-month period of 2012 also included costs associated with the separation of Phillips 66.

Exploration expenses decreased 18 percent in the third quarter of 2012 and increased 65 percent in the nine-month period of 2012. The decrease in the third quarter of 2012 was mainly due to lower dry hole costs. The increase in the nine-month period was mostly due to the impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of the indefinite suspension of the project in the first quarter of 2012.

DD&A decreased 7 percent in the nine-month period of 2012, primarily due to lower production volumes as a result of asset dispositions and lower production in China, partially offset by higher production volumes in the Lower 48.

Impairments increased $296 million in the nine-month period of 2012, largely due to the $213 million impairment of capitalized project development costs associated with the Mackenzie Gas Project in the first quarter of 2012, as well as the $78 million increase in the asset retirement obligation for the Don Field in the United Kingdom, which has ceased production. For additional information, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 25 percent and 10 percent in the third quarter and nine-month period of 2012, respectively, mostly due to lower production taxes as a result of lower crude oil production volumes. Lower crude oil prices also contributed to the decrease in the third quarter of 2012.

Interest and debt expense for the third quarter and nine-month period of 2012 decreased 30 percent and 25 percent, respectively, primarily due to higher capitalized interest on projects and lower interest expense due to lower average debt levels.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

 

37


Table of Contents

Summary Operating Statistics

                                                           
     Three Months  Ended
September 30
     Nine Months Ended
September  30
 
     2012      2011      2012      2011  
  

 

 

    

 

 

 

Average Net Production

           

Crude oil (MBD)*

     578        593        612        659  

Natural gas liquids (MBD)

     155        148        159        145  

Bitumen (MBD)

     92        64        88        65  

Natural gas (MMCFD)**

     4,199        4,397        4,258        4,539  

 

 

Total Production (MBOED)***

     1,525        1,538        1,569        1,626  

 

 
     Dollars Per Unit  

Average Sales Prices

           

Crude oil (per barrel)

   $ 102.72        106.61        106.92        105.78  

Natural gas liquids (per barrel)

     40.39        55.61        46.02        54.97  

Bitumen (per barrel)

     56.86        58.14        56.23        59.69  

Natural gas (per thousand cubic feet)

     4.56        5.45        4.60        5.39  

 

 
     Millions of Dollars  

Exploration Expenses

           

General administrative; geological and geophysical; and lease rentals

   $ 150        115        465        416  

Leasehold impairment

     63        40        627        122  

Dry holes

     6        111        76        168  

 

 
   $ 219        266        1,168        706  

 

 

    *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.

***Thousands of barrels of oil equivalent per day.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At September 30, 2012, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Libya, Nigeria, Algeria, Qatar and Russia.

Total production averaged 1,525 MBOED in the third quarter of 2012, a decrease of 1 percent compared with the third quarter of 2011. Production for the nine-month period of 2012 averaged 1,569 MBOED, down 4 percent from the corresponding period of 2011. The decreases in both periods of 2012 were mostly due to normal field decline, the impact from dispositions and higher planned and unplanned downtime. These decreases were largely offset by additional production from major projects, mainly from shale plays in the Lower 48 and ramp-up of new phases at FCCL, the resumption of production in Libya following a period of civil unrest in 2011, and increased drilling programs. Reduced production in Bohai Bay, China also contributed to the decrease in the nine-month period of 2012.

 

38


Table of Contents

Segment Results

Alaska

                                                           
     Three Months  Ended
September 30
     Nine Months Ended
September 30
 
     2012      2011      2012      2011  
  

 

 

    

 

 

 

Income From Continuing Operations (millions of dollars)

   $ 535        502        1,706        1,558  

 

 

Average Net Production

           

Crude oil (MBD)

     157        187        185        197  

Natural gas liquids (MBD)

     10        12        15        15  

Natural gas (MMCFD)

     51        56        55        61  

 

 

Total Production (MBOED)

     176        208        209        222  

 

 

Average Sales Prices

           

Crude oil (dollars per barrel)

   $ 106.53        107.26        110.54        105.19  

Natural gas (dollars per thousand cubic feet)

     3.97        5.04        4.21        4.52  

 

 

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of September 30, 2012, Alaska contributed 23 percent of our worldwide liquids production and 1 percent of our natural gas production.

Our Alaska operations reported earnings of $535 million in the third quarter of 2012, a 7 percent increase compared with the same period in 2011. Earnings for the nine-month period of 2012 were $1,706 million, a 9 percent increase compared with the same period in 2011. The improvement in earnings in the third quarter of 2012 was largely due to lower production taxes, and to a lesser extent, lower DD&A. These improvements were mostly due to lower crude oil production as a result of major planned turnaround activity in Prudhoe and the Western North Slope in the third quarter of 2012. The impact to earnings from lower crude oil production was more than offset by sales from inventory, which contributed approximately $120 million after-tax to third quarter 2012 earnings. Lower LNG sales volumes partly offset the increase in earnings in the third quarter of 2012. Earnings in the nine-month period of 2012 benefitted from higher crude oil and LNG prices, the absence of the $54 million after-tax impairment of our investment associated with the cancellation of the Denali gas pipeline project in the second quarter of 2011, and lower production taxes and DD&A. These increases were partially offset by lower crude oil production volumes and higher operating expenses.

Production averaged 176 MBOED in the third quarter of 2012, a decrease of 15 percent compared with the third quarter of 2011. Production for the nine-month period of 2012 was 209 MBOED, a 6 percent decrease compared with the corresponding period in 2011. The reductions in both periods of 2012 were mainly due to normal field decline and major planned turnaround activity during the third quarter of 2012, partly offset by lower unplanned downtime.

 

39


Table of Contents

Lower 48 and Latin America

                                                           
     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2012      2011      2012      2011  
  

 

 

    

 

 

 

Income From Continuing Operations (millions of dollars)

   $ 182        334        556        996  

 

 

Average Net Production

           

Crude oil (MBD)

     124        95        119        89  

Natural gas liquids (MBD)

     87        79        85        72  

Natural gas (MMCFD)

     1,507        1,561        1,489        1,557  

 

 

Total Production (MBOED)

     462        434        452        421  

 

 

Average Sales Prices

           

Crude oil (dollars per barrel)

   $ 90.06        89.13        92.84        92.28  

Natural gas liquids (dollars per barrel)

     31.40        52.25        36.89        50.08  

Natural gas (dollars per thousand cubic feet)

     2.64        4.15        2.47        4.16  

 

 

As of September 30, 2012, Lower 48 and Latin America contributed 24 percent of our worldwide liquids production and 35 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. Also included in this segment is our 39 percent equity interest in Phoenix Park Gas Processors Limited, which processes natural gas in Trinidad and markets natural gas liquids in the Atlantic Basin, and the Wingate fractionation plant located in Gallup, New Mexico.

Lower 48 and Latin America operations reported earnings of $182 million in the third quarter of 2012, a 46 percent decrease compared with the same period in 2011. Earnings for the nine-month period of 2012 were $556 million, a 44 percent decrease compared with the same period in 2011. The decreases for both periods of 2012 were primarily the result of substantially lower natural gas and natural gas liquids prices and higher DD&A, partially offset by higher crude oil and natural gas liquids volumes. In addition, third quarter 2012 earnings benefitted from lower dry hole costs and the gain on disposition of our interest in Block 39 in Peru, partially offset by higher undeveloped leasehold impairments. For the nine-month period of 2012, lower gains from asset dispositions, higher operating expenses and lower natural gas volumes also contributed to the decrease in earnings.

Average production in the Lower 48 increased 6 percent in the third quarter and 7 percent in the nine-month period of 2012, while average liquids production increased 21 percent and 26 percent over the same respective periods. The increases in both periods of 2012 were mainly due to new production, primarily from the Eagle Ford, Bakken and Permian areas, and improved drilling and well performance, partially offset by normal field decline, and planned and unplanned downtime.

Peru Blocks 123 and 129

In October 2012, we announced our decision not to pursue further exploration activities in Peru Blocks 123 and 129. This decision to withdraw prior to the next exploration period is part of our strategic plan to optimize our portfolio of assets.

 

40


Table of Contents

Canada

 

                                                           
     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2012     2011      2012     2011  
  

 

 

    

 

 

 

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

   $ (31     73        (674 )      201  

 

 

Average Net Production

         

Crude oil (MBD)

     14       12        13       12  

Natural gas liquids (MBD)

     25       25        24       25  

Bitumen (MBD)

         

Consolidated operations

     12       11        11       10  

Equity affiliates

     80       53        77       55  

 

 

Total bitumen

     92       64        88       65  

Natural gas (MMCFD)

     874       929        867       940  

 

 

Total Production (MBOED)

     277       256        270       259  

 

 

Average Sales Prices

         

Crude oil (dollars per barrel)

   $ 77.19       85.02        78.44       85.72  

Natural gas liquids (dollars per barrel)

     45.31       58.90        49.43       57.82  

Bitumen (dollars per barrel)

         

Consolidated operations

     56.23       45.79        58.41       49.79  

Equity affiliates

     56.95       60.65        55.90       61.50  

Total bitumen

     56.86       58.14        56.23       59.69  

Natural gas (dollars per thousand cubic feet)

     2.05       3.56        1.88       3.63  

 

 

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, 2012, Canada contributed 15 percent of our worldwide liquids production and 20 percent of our natural gas production.

Canada operations reported losses of $31 million and $674 million in the third quarter and nine-month period of 2012, respectively, versus earnings of $73 million and $201 million in the corresponding periods of 2011. Earnings in the nine-month period of 2012 included the $520 million after-tax impairment of the Mackenzie Gas Project and associated undeveloped leaseholds. The decreases in both periods of 2012 also reflected lower prices, predominantly natural gas, and higher operating and DD&A expenses from our FCCL venture. These decreases were partly offset by higher bitumen volumes and lower DD&A.

Average production increased 8 percent in the third quarter of 2012 and 4 percent in the nine-month period of 2012. The increases in both periods were largely due to new production from Christina Lake Phases C and D in FCCL. Normal field decline and the impact of asset dispositions were largely offset by additional production from western Canada.

 

41


Table of Contents

Europe

                                                           
     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2012      2011      2012      2011  
  

 

 

    

 

 

 

Income From Continuing Operations (millions of dollars)

   $ 132        266        1,190        1,265  

 

 

Average Net Production

           

Crude oil (MBD)

     117        150        137        167  

Natural gas liquids (MBD)

     5        9        8        11  

Natural gas (MMCFD)

     414        511        529        616  

 

 

Total Production (MBOED)

     191        245        233        281  

 

 

Average Sales Prices

           

Crude oil (dollars per barrel)

   $ 109.67        115.03        113.69        112.39  

Natural gas liquids (dollars per barrel)

     57.62        58.05        56.97        59.32  

Natural gas (dollars per thousand cubic feet)

     8.87        9.08        9.53        9.04  

 

 

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. As of September 30, 2012, our Europe operations contributed 16 percent of our worldwide liquids production and 13 percent of our natural gas production.

Earnings for our Europe operations were $132 million in the third quarter of 2012, a 50 percent decrease compared with the same period in 2011. Earnings for the nine-month period of 2012 were $1,190 million, a 6 percent decrease compared with the same period in 2011. Earnings for both periods of 2012 were impacted by $170 million in additional income tax expense, as a result of legislation enacted in the United Kingdom in July 2012, which restricted corporate tax relief on decommissioning costs to 50 percent. The additional tax expense resulted from the revaluation of deferred tax balances. Earnings for both periods of 2011 included $234 million in additional income tax expense, as a result of U.K. tax legislation enacted in July 2011, which increased the U.K. corporate tax rate applicable to upstream activity. This additional tax expense consisted of $106 million for the revaluation of deferred tax liabilities; $75 million to reflect the higher tax rates from the effective date of the legislation, March 24, 2011, through June 30, 2011; and $53 million for the impact of the higher tax rates on third quarter 2011 earnings.

Excluding the impact from the U.K. tax increases, the decrease in earnings in both periods of 2012 was primarily the result of substantially lower volumes. Earnings in the third quarter of 2012 were also impacted by losses on foreign currency transactions and lower crude oil prices, partly offset by lower DD&A. Earnings for the nine-month period of 2012 also benefitted from the $285 million after-tax gain on sale of our interests in the Statfjord and Alba fields, lower DD&A and gains on foreign currency transactions, partly offset by the $30 million after-tax impairment of the non-producing Don Field in the United Kingdom, due to an increase in the asset retirement obligation.

Average production decreased 22 percent in the third quarter and 17 percent in the nine-month period of 2012. The decreases in both periods of 2012 were mostly due to field decline, dispositions and slightly higher unplanned downtime, partly offset by production from new wells in Norway. Third quarter 2012 production was also impacted by slightly higher planned downtime in the United Kingdom.

In December 2011, we entered into an agreement to sell our interests in the MacCulloch and Nicol fields in the United Kingdom. The sales of these interests are expected to close in the fourth quarter of 2012, subject to agreement on final terms.

 

42


Table of Contents

Asia Pacific and Middle East

 

                                                           
     Three Months Ended      Nine Months Ended  
     September 30      September 30  
     2012      2011      2012      2011  
  

 

 

    

 

 

 

Income From Continuing Operations (millions of dollars)

   $ 683        482        3,231        2,330   

 

 

Average Net Production

           

Crude oil (MBD)

           

Consolidated operations

     75        81        63        108  

Equity affiliates

     14        15        15        16  

 

 

Total crude oil

     89        96        78        124  

 

 

Natural gas liquids (MBD)

           

Consolidated operations

     17        13        16        12  

Equity affiliates

     7        7        7        7  

 

 

Total natural gas liquids

     24        20        23        19  

 

 

Natural gas (MMCFD)

           

Consolidated operations

     709        700        664        705  

Equity affiliates

     449        479        482        503  

 

 

Total natural gas

     1,158        1,179        1,146        1,208  

 

 

Total Production (MBOED)

     306        312        293        344  

 

 

Average Sales Prices

           

Crude oil (dollars per barrel)

           

Consolidated operations

   $ 105.12        112.44        110.19        109.70  

Equity affiliates

     101.75        107.95        107.86        107.41  

Total crude oil

     104.60        111.81        109.74        109.44  

Natural gas liquids (dollars per barrel)

           

Consolidated operations

     71.06        71.77        77.60        74.34  

Equity affiliates

     62.18        70.79        73.67        72.32  

Total natural gas liquids

     68.60        71.40        76.40        73.55  

Natural gas (dollars per thousand cubic feet)

           

Consolidated operations

     10.64        10.68        10.80        9.76  

Equity affiliates

     2.82        2.85        2.72        2.91  

Total natural gas

     7.62        7.51        7.41        6.91  

 

 

The Asia Pacific and Middle East segment has producing operations in China, Indonesia, Australia, the Timor Sea and Qatar, as well as exploration activities in Malaysia, Bangladesh and Brunei. As of September 30, 2012, Asia Pacific and Middle East contributed 12 percent of our worldwide liquids production and 27 percent of our natural gas production.

Asia Pacific and Middle East operations reported earnings of $683 million in the third quarter of 2012, a 42 percent increase compared with the same period in 2011. Earnings for the nine-month period of 2012 were $3,231 million, a 39 percent increase compared with the same period in 2011. The increase in earnings in both periods of 2012 reflected a $133 million after-tax loss recognized in the third quarter of 2012 due to the further dilution of our equity interest in APLNG from 42.5 percent to 37.5 percent, which was more than offset by the absence of the $279 million after-tax loss on the initial dilution of our interest in APLNG from 50 percent to 42.5 percent in the third quarter of 2011. Also contributing to the improvement in third quarter 2012 earnings were gains on foreign currency transactions, lower dry hole costs, the absence of Bohai Bay expenses incurred in

 

43


Table of Contents

the third quarter of 2011, and lower taxes. These increases were partially offset by lower volumes, primarily as a result of our Vietnam disposition, and higher DD&A. Earnings in the nine-month period of 2012 also benefitted from the $931 million after-tax gain on sale of our Vietnam business, significantly higher LNG prices, lower DD&A, as well as a $72 million tax-related adjustment, largely offset by lower crude oil and LNG volumes and an $89 million after-tax charge related to the Bohai Bay settlement with the China State Oceanic Administration.

Production averaged 306 MBOED in the third quarter of 2012, a decrease of 2 percent compared with the third quarter of 2011. For the nine-month period of 2012, production averaged 293 MBOED, a decrease of 15 percent compared with the same period of 2011. The decrease in the third quarter of 2012 was largely due to the disposition of our Vietnam business, normal field decline and unplanned downtime in Qatar, partly offset by higher production in China. Production in the nine-month period of 2012 was also impacted by dispositions and decline, as well as lower production in China and higher planned downtime at our Bayu-Undan Field and Darwin LNG Facility.

APLNG

In July 2012, we sanctioned the development of the second 4.5-million-tonnes-per-year LNG production train for our APLNG coal seam gas to LNG project. LNG exports from the second train are expected to commence in early 2016 under binding sales agreements to China Petrochemical Corporation (Sinopec) and The Kansai Electric Power Co. Inc. Upon sanctioning of the second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed to additional shares in APLNG, which increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin Energy’s ownership interest diluted from 42.5 percent to 37.5 percent.

APLNG executed project financing agreements for an $8.5 billion project finance facility during the third quarter of 2012 and began drawing on the financing in October 2012. Our reduced ownership interest, coupled with Sinopec’s estimated $2.1 billion injection into APLNG associated with the dilution and APLNG’s successful placement of the $8.5 billion of project financing, will lower our future capital requirements to fund the project. We also plan to evaluate opportunities to further reduce our ownership interest in APLNG.

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.

For additional information, see Note 3—Variable Interest Entities (VIEs), Note 6—Investments, Loans and Long-Term Receivables and Note 12—Guarantees, in the Notes to Consolidated Financial Statements.

China—Bohai Bay

At the end of the third quarter of 2012, Peng Lai’s net production was approximately 45 MBOED. We continue to seek approval for the revised overall development plan, while the environmental impact assessment was approved in October 2012. Oil offtake should remain fairly level for the remainder of 2012 under an approved interim operations resumption plan.

 

44


Table of Contents

Other International

                                                           
     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2012      2011      2012      2011  
  

 

 

    

 

 

 

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

   $ 567        53        634        251  

 

 

Average Net Production

           

Crude oil (MBD)

           

Consolidated operations

     66        27        65        38  

Equity affiliates

     11        26        15        32  

 

 

Total crude oil

     77        53        80        70  

 

 

Natural gas liquids (MBD)

     4        3        4        3  

Natural gas (MMCFD)

     195        161        172        157  

 

 

Total Production (MBOED)

     113        83        112        99  

 

 

Average Sales Prices

           

Crude oil (dollars per barrel)

           

Consolidated operations

   $ 107.68        114.84        111.76        111.07  

Equity affiliates

     90.02        102.19        98.75        102.13  

Total crude oil

     105.71        108.69        109.43        106.94  

Natural gas liquids (dollars per barrel)

     14.26        12.60        13.99        13.15  

Natural gas (dollars per thousand cubic feet)

     3.44        2.36        2.84        2.19  

 

 

The Other International segment includes producing operations in Nigeria, Libya, Algeria and Russia, as well as exploration activities in Angola and the Caspian Sea. As of September 30, 2012, Other International contributed 10 percent of our worldwide liquids production and 4 percent of our natural gas production.

Other International operations reported earnings of $567 million in the third quarter of 2012, an increase of $514 million compared with the same period in 2011. Earnings for the nine-month period of 2012 were $634 million, an increase of $383 million compared with the same period in 2011. The increase in both periods of 2012 was primarily the result of the $443 million after-tax gain on disposition of our interest in NMNG. Higher earnings from Libya in both periods of 2012 also contributed to the increase, as a result of the resumption of production following a period of civil unrest in 2011. In addition, lower volumes in Russia in the nine-month period of 2012 were partly offset by lower taxes.

Average production increased 36 percent and 13 percent in the third quarter and nine-month period of 2012, respectively. The increases in both periods of 2012 were mostly due to the resumption of production in Libya, partly offset by field decline in Russia and the disposition of our interest in NMNG.

Nigeria Flooding

Our production operations in Nigeria are currently exposed to severe flooding, and, as a result, our fourth quarter drilling program has been interrupted and production may be impacted. We hold a 20 percent interest in the affected Oil Mining Leases and Kwale Gas Plant. For the first nine months of 2012, our net production from Nigeria averaged 43 MBOED. Future impacts are unknown at this time.

 

45


Table of Contents

LUKOIL Investment

                                                           
     Millions of Dollars  
     Three Months Ended
September 30
     Nine Months Ended
September 30
 
     2012      2011      2012      2011  
  

 

 

    

 

 

 

Income From Continuing Operations

   $                        239  

 

 

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.

Corporate and Other

                                                           
     Millions of Dollars  
     Three Months Ended
September 30
    Nine Months Ended
September 30
 
     2012     2011     2012     2011  
  

 

 

   

 

 

 

Income (Loss) From Continuing Operations

        

Net interest

   $ (214     (174     (503 )      (538

Corporate general and administrative expenses

     (128     (33     (246 )      (137

Technology

     46       44       6       43  

Separation costs

     (7            (80 )        

Other

     46       (52     (13 )      (96

 

 
   $ (257     (215     (836 )      (728

 

 

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 23 percent in the third quarter of 2012 and decreased 7 percent in the first nine months of 2012. The increase in the third quarter of 2012 was primarily due to a $68 million after-tax premium on early debt retirement, partly offset by higher capitalized interest on projects and lower interest expense due to lower debt levels. In the nine-month period of 2012, higher capitalized interest on projects and lower interest expense more than offset the premium on early debt retirement and lower interest income.

Corporate general and administrative expenses increased $95 million and $109 million in the third quarter and nine-month period of 2012, mostly due to $82 million after-tax of pension settlement expense. Higher costs related to compensation and benefit plans and corporate contributions also contributed to the increase in the nine-month period of 2012.

Technology includes our investment in new technologies or businesses, net of licensing revenues. Activities are focused on heavy oil and oil sands, unconventional reservoirs, subsurface technology, liquefied natural gas, arctic and deepwater, as well as sustainability technology. Technology earnings decreased by 86 percent in the nine-month period of 2012, mostly as a result of lower licensing revenues.

Separation costs consist of expenses related to the separation of our downstream businesses into a stand-alone, publicly traded company, Phillips 66. Expenses incurred in the third quarter and the nine-month period of 2012 primarily included costs related to compensation and benefit plans.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment.

 

46


Table of Contents

“Other” expenses improved $98 million in the third quarter and $83 million in the nine-month period of 2012. Both periods in 2012 mainly benefitted from foreign currency transaction gains, in addition to a $39 million after-tax settlement. In addition, the nine-month period of 2012 benefitted from the absence of various tax-related adjustments in 2011, which was partly offset by higher environmental expenses.

Our Corporate and Other net costs are estimated to be $1.1 billion after-tax for the full-year 2012.

 

47


Table of Contents

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

                             
     Millions of Dollars  
     September 30
2012
    December 31
2011
 
  

 

 

 

Short-term debt

   $ 2,335        1,013   

Total debt

     21,117        22,623   

Total equity*

     47,877        65,749   

Percent of total debt to capital**

     31     26   

Percent of floating-rate debt to total debt***

     11     10   

 

 
* Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.

** Capital includes total debt and total equity.

*** Includes effect of interest rate swaps.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from continuing operating activities is the primary source of funding. In addition, during the first nine months of 2012, we received $2,088 million in proceeds from asset sales and $7,818 million from a special cash distribution from Phillips 66, primarily using the proceeds from the $5.8 billion in Senior Notes issued by Phillips 66 in March 2012, as well as a portion of the approximately $3.6 billion in cash transferred to Phillips 66 at separation, consisting of funds received from the $2.0 billion term loan which Phillips 66 entered into immediately prior to the separation, and approximately $1.6 billion of cash held by Phillips 66 subsidiaries. The proceeds from the special cash distribution may be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, in each case within twelve months following the distribution. At September 30, 2012, the remaining balance of this cash distribution was $2,468 million and was included in the “Restricted cash” line on our consolidated balance sheet.

During the first nine months of 2012, available cash and restricted cash was used to support our ongoing capital expenditures and investments program, repurchase common stock, pay dividends and repay debt. Total dividends paid on our common stock during the first nine months of 2012 were $2,469 million. During the first nine months of 2012, cash and cash equivalents decreased by $4,512 million to $1,268 million.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs, and our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, dividend payments, required debt payments and the funding requirements to FCCL Partnership.

Significant Sources of Capital

Operating Activities

Cash provided by continuing operating activities was $9,846 million for the first nine months of 2012, compared with $11,396 million for the corresponding period of 2011, a 14 percent decrease. The decrease was primarily caused by lower volumes, primarily due to dispositions, and lower natural gas and natural gas liquids prices.

While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

 

48


Table of Contents

The level of our production volumes also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success, and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.

Asset Sales

Proceeds from asset sales during the first nine months of 2012 were $2,088 million, primarily from the sale of our Vietnam business, the sale of our equity interest in NMNG and the sale of our interest in the Statfjord and Alba fields in the North Sea. This compares with proceeds of $1,954 million in the first nine months of 2011, which mainly included the sale of our remaining interest in LUKOIL and certain properties located in the Lower 48. We plan to raise up to an additional $8 billion from asset sales by the end of 2013.

Commercial Paper and Credit Facilities

At September 30, 2012, we had a revolving credit facility totaling $7.5 billion expiring in August 2016. Our revolving credit facility may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.

Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreement calls for commitment fees on available but unused amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.15 billion commercial paper program, which is used to fund commitments relating to the QG3 Project. At September 30, 2012, and December 31, 2011, we had no direct borrowings under the revolving credit facilities, with no letters of credit issued at September 30, 2012, and $40 million at December 31, 2011. In addition, under the two ConocoPhillips commercial paper programs, $1,540 million of commercial paper was outstanding at September 30, 2012, compared with $1,128 million at December 31, 2011. Since we had $1,540 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facilities at September 30, 2012.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.

For information about guarantees, see Note 12—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

 

49


Table of Contents

Capital Requirements

For information about our capital expenditures and investments, see the “Capital Spending” section.

Our debt balance at September 30, 2012, was $21.1 billion, a decrease of $1.5 billion from the balance at December 31, 2011. During the first nine months of 2012, we repaid bonds totaling $1.5 billion. We incurred a before-tax loss on the redemption of $79 million, consisting of a make-whole premium and unamortized issuance costs. In October 2012, we repaid $897 million of 4.75% notes upon maturity.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL. 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 $763 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2012, consolidated balance sheet. The principal portion of these payments, which totaled $546 million in the first nine months of 2012, 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.

In July 2012, we announced a dividend of 66 cents per share. The dividend was paid September 4, 2012, to stockholders of record at the close of business on July 23, 2012. Additionally, in October 2012, we announced a dividend of 66 cents per share. The dividend will be paid December 3, 2012, to stockholders of record at the close of business on October 15, 2012.

On December 2, 2011, our Board of Directors authorized the purchase of up to an additional $10 billion of our common stock over the subsequent two years. Since our share repurchase programs began in 2010, share repurchases totaled 300 million shares at a cost of $20.1 billion through September 30, 2012. Future share repurchases will be made opportunistically, contingent upon commodity prices and proceeds from asset dispositions.

Capital Spending

Capital Expenditures and Investments

                             
     Millions of Dollars  
     Nine Months Ended
September 30
 
     2012      2011  
  

 

 

 

Alaska

   $ 596        585  

Lower 48 and Latin America

     3,894        2,782  

Canada

     1,550        1,159  

Europe

     2,095        1,540  

Asia Pacific and Middle East

     2,053        1,763  

Other International

     1,016        801  

LUKOIL

               

Corporate and Other

     133        117  

 

 
   $ 11,337        8,747  

 

 

United States

   $ 4,621        3,483  

International

     6,716        5,264  

 

 
   $ 11,337        8,747  

 

 

 

50


Table of Contents

During the first nine months of 2012, capital expenditures and investments supported key exploration and development programs, primarily:

 

   

Oil and natural gas exploration and development activities in the Lower 48, including the Eagle Ford and Bakken shale plays, and the Permian Basin.

   

Exploration leases and wells in deepwater Gulf of Mexico.

   

Oil sands development and ongoing liquids-focused plays in Canada.

   

Further development of coalbed methane projects associated with the APLNG joint venture in Australia.

   

Continued development of new fields offshore Malaysia and ongoing exploration and development activity offshore Indonesia and Australia.

   

In Europe, development activities in the Ekofisk, Jasmine and Clair Ridge areas, as well as investment in a joint venture in Poland.

   

The Kashagan Field in the Caspian Sea.

   

Leasehold acquisitions in Angola.

Contingencies

A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. 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. In the case of 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.

Legal Matters

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, is required.

 

51


Table of Contents

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 64, 65 and 66 of our 2011 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability from the Environmental Protection Agency (EPA) and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2011, we reported we had been notified of potential liability under CERCLA and comparable state laws at 74 sites around the United States. As of September 30, 2012, we had resolved 2 sites and transferred 61 sites to Phillips 66, bringing the number of unresolved sites with potential liability to 11.

At September 30, 2012, our balance sheet included a total environmental accrual of $380 million, compared with $922 million at December 31, 2011. A significant portion of our environmental contingencies at December 31, 2011, was transferred to Phillips 66. We expect to incur a substantial amount of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect on our results of operations or financial position as a result of compliance with current environmental laws and regulations.

Climate Change

There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, to the extent enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include the EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)) and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that trigger regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects.

For other examples of legislation or precursors for possible regulation and factors on which the ultimate impact on our financial performance will depend, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 66 and 67 of our 2011 Annual Report on Form 10-K.

 

52


Table of Contents

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by 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.

We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:

 

   

Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices.

   

Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.

   

Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.

   

Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for exploration and production projects.

   

Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, bitumen and LNG.

   

Inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects, construction of LNG terminals or regasification facilities; comply with government regulations; or make capital expenditures required to maintain compliance.

   

Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future exploration and production and LNG projects.

   

Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events, terrorism or cyber attacks.

   

International monetary conditions and exchange controls.

   

Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.

   

Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.

   

Liability resulting from litigation.

   

General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG or natural gas liquids pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.

   

Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.

   

Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.

   

Delays in, or our inability to implement, our asset disposition plan.

   

Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes.

   

The factors generally described in Item 1A—Risk Factors in our 2011 Annual Report on Form 10-K.

 

53


Table of Contents
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the nine months ended September 30, 2012, does not differ materially from that discussed under Item 7A in our 2011 Annual Report on Form 10-K.

 

Item 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of September 30, 2012, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of September 30, 2012.

There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

54


Table of Contents

PART II. OTHER INFORMATION

 

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the third quarter of 2012 and any material developments with respect to matters previously reported in ConocoPhillips’ 2011 Annual Report on Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission (SEC) regulations.

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, we entered into an Indemnification and Release Agreement which provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters, such as legal proceedings. We have included matters where we remain a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim against us.

New Matters

On September 19, 2012, the Bay Area Air Quality Management District (District) issued a $213,500 demand to settle fourteen Notices of Violation (NOVs) issued in 2009 and 2010 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery. Phillips 66 is working with the District to resolve this matter.

On October 15, 2012, the District issued a $313,000 demand to settle thirteen NOVs issued in 2010 and 2011 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery. Phillips 66 is working with the District to resolve this matter.

Matters Previously Reported

Phillips 66 was one of several companies who entered Administrative Settlement Agreements (ASAs) with the U.S. Environmental Protection Agency (EPA) to settle allegations it had used invalid Renewable Identification Numbers (RINs) for its 2010 and 2011 fuel program compliance. Under this Agreement, Phillips 66 will pay a maximum of $350,000 in penalties for the use of invalid RINs. Payments are made upon demand from the EPA. To date, $250,000 has been paid and it is anticipated the EPA will demand the final $100,000 in 2013.

Phillips 66 has settled an allegation that it did not immediately notify the EPA of certain releases in 2010 and 2011 at the Phillips 66 Wood River Refinery. The facility will be paying a fine of $25,224 and perform on-site supplemental environmental projects valued at $125,000.

 

55


Table of Contents
Item 1A. RISK FACTORS

You should carefully consider the following risk factor, in addition to the risk factors disclosed in Item 1A of our 2011 Annual Report on Form 10-K.

Our operations present hazards and risks that require significant and continuous oversight.

Our technologies, systems and networks may be subject to cybersecurity breaches. Although we have experienced occasional, actual or attempted breaches of our cybersecurity, none of these breaches has had a material effect on our business, operations or reputation. If our systems for protecting against cybersecurity risks prove to be insufficient, we could be adversely affected by having our business systems compromised, our proprietary information altered, lost or stolen, or our business operations disrupted.

There have been no other material changes from the risk factors disclosed in Item 1A of our 2011 Annual Report on Form 10-K.

 

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

 

                                                           
                          Millions of Dollars  
Period    Total Number of
Shares Purchased*
     Average Price
Paid per Share
     Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs**
    

Approximate Dollar
Value of Shares

that May Yet Be
Purchased Under the
Plans or Programs

 

 

 

July 1-31, 2012

     2,749,572      $ 54.58        2,747,541      $ 4,901  

August 1-31, 2012

     7,179        56.45        —           4,901  

September 1-30, 2012

     8,733        57.49        —           4,901  

 

 

Total

     2,765,484      $ 54.59        2,747,541     

 

 
  * Includes the repurchase of common shares from Company employees in connection with the Company’s broad-based employee incentive plans.
** On December 2, 2011, we announced a share repurchase program for up to $10 billion of common stock over the next two years. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

 

56


Table of Contents
Item 6. EXHIBITS

 

10.1*    Amendment and Restatement of the ConocoPhillips Key Employee Change in Control Severance Plan.
10.2*    First Amendment to the Defined Contribution Make-Up Plan of ConocoPhillips – Title II.
10.3*    ConocoPhillips Clawback Policy.
12*    Computation of Ratio of Earnings to Fixed Charges.
31.1*    Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*    Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32*    Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*    XBRL Instance Document.
101.SCH*    XBRL Schema Document.
101.CAL*    XBRL Calculation Linkbase Document.
101.LAB*    XBRL Labels Linkbase Document.
101.PRE*    XBRL Presentation Linkbase Document.
101.DEF*    XBRL Definition Linkbase Document.

* Filed herewith.

 

57


Table of Contents

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

CONOCOPHILLIPS
/s/ Glenda M. Schwarz
Glenda M. Schwarz
Vice President and Controller
(Chief Accounting and Duly Authorized Officer)

October 30, 2012

 

58