UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

ý

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

 

For the quarterly period ended September 30, 2005

 

OR

 

o

 

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   ý   No   o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).  Yes   ý   No   o

 

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

 

The registrant had 1,387,565,073 shares of common stock, $.01 par value, outstanding at September 30, 2005.

 

 



 

CONOCOPHILLIPS

 

TABLE OF CONTENTS

 

 

Page

Part I — Financial Information

 

 

 

 

 

Item 1. Financial Statements

 

 

Consolidated Income Statement

1

 

Consolidated Balance Sheet

2

 

Consolidated Statement of Cash Flows

3

 

Notes to Consolidated Financial Statements

4

 

Supplementary Information—Condensed Consolidating Financial Information

25

 

 

 

 

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

34

 

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

60

 

 

 

 

Item 4. Controls and Procedures

60

 

 

 

 

Part II — Other Information

 

 

 

 

 

Item 1. Legal Proceedings

61

 

 

 

 

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

61

 

 

 

 

Item 6. Exhibits

62

 

 

 

 

Signature

63

 

 



 

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

 

 

 

2005

 

2004*

 

2005

 

2004*

 

Revenues

 

 

 

 

 

 

 

 

 

Sales and other operating revenues (1)(2)

 

$

48,745

 

34,350

 

128,184

 

95,691

 

Equity in earnings of affiliates

 

872

 

389

 

2,626

 

980

 

Other income

 

42

 

2

 

381

 

173

 

Total Revenues

 

49,659

 

34,741

 

131,191

 

96,844

 

 

 

 

 

 

 

 

 

 

 

Costs and Expenses

 

 

 

 

 

 

 

 

 

Purchased crude oil, natural gas and products (3)

 

34,508

 

23,100

 

88,603

 

63,198

 

Production and operating expenses

 

1,982

 

1,807

 

6,081

 

5,312

 

Selling, general and administrative expenses

 

612

 

529

 

1,690

 

1,513

 

Exploration expenses

 

140

 

205

 

432

 

511

 

Depreciation, depletion and amortization

 

1,049

 

938

 

3,075

 

2,768

 

Property impairments

 

 

12

 

31

 

63

 

Taxes other than income taxes (1)

 

4,606

 

4,336

 

13,758

 

12,878

 

Accretion on discounted liabilities

 

46

 

49

 

135

 

126

 

Interest and debt expense

 

122

 

101

 

387

 

405

 

Foreign currency transaction losses (gains)

 

34

 

(4

)

52

 

(53

)

Minority interests

 

6

 

8

 

21

 

29

 

Total Costs and Expenses

 

43,105

 

31,081

 

114,265

 

86,750

 

Income from continuing operations before income taxes

 

6,554

 

3,660

 

16,926

 

10,094

 

Provision for income taxes

 

2,750

 

1,649

 

7,068

 

4,467

 

Income From Continuing Operations

 

3,804

 

2,011

 

9,858

 

5,627

 

Income (loss) from discontinued operations

 

(4

)

(5

)

(8

)

70

 

Net Income

 

$

3,800

 

2,006

 

9,850

 

5,697

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income Per Share of Common Stock (dollars) (4)

 

 

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

2.73

 

1.45

 

7.06

 

4.08

 

Discontinued operations

 

 

 

(.01

)

.05

 

Net Income

 

$

2.73

 

1.45

 

7.05

 

4.13

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

2.68

 

1.43

 

6.94

 

4.03

 

Discontinued operations

 

 

 

 

.05

 

Net Income

 

$

2.68

 

1.43

 

6.94

 

4.08

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends Paid Per Share of Common Stock (dollars) (4)

 

$

.31

 

.22

 

.87

 

.65

 

 

 

 

 

 

 

 

 

 

 

Average Common Shares Outstanding (in thousands) (4)

 

 

 

 

 

 

 

 

 

Basic

 

1,393,943

 

1,383,652

 

1,396,180

 

1,378,428

 

Diluted

 

1,417,796

 

1,403,432

 

1,419,898

 

1,397,038

 

 

 

 

 

 

 

 

 

 

 

(1) Includes excise, value added and other similar taxes on petroleum products sales:

 

$

4,292

 

4,079

 

12,785

 

12,073

 

(2) Includes sales related to purchases/sales with the same counterparty:

 

5,879

 

3,863

 

15,284

 

10,662

 

(3) Includes purchases related to purchases/sales with the same counterparty:

 

5,778

 

3,708

 

15,056

 

10,389

 

(4) Per-share amounts and average number of common shares outstanding in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005. 

 

*Certain amounts reclassified to conform to current year presentation.

 

See Notes to Consolidated Financial Statements.

 

 

1



 

Consolidated Balance Sheet

ConocoPhillips

 

 

 

Millions of Dollars

 

 

 

September 30

 

December 31

 

 

 

2005

 

2004

 

Assets

 

 

 

 

 

Cash and cash equivalents

 

$

2,803

 

1,387

 

Accounts and notes receivable (net of allowance of $64 million in 2005 and $55 million in 2004)

 

9,962

 

5,449

 

Accounts and notes receivable—related parties

 

444

 

3,339

 

Inventories

 

4,838

 

3,666

 

Prepaid expenses and other current assets

 

2,413

 

986

 

Assets of discontinued operations held for sale

 

144

 

194

 

Total Current Assets

 

20,604

 

15,021

 

Investments and long-term receivables

 

14,802

 

10,408

 

Net properties, plants and equipment

 

52,482

 

50,902

 

Goodwill

 

14,927

 

14,990

 

Intangibles

 

1,043

 

1,096

 

Other assets

 

514

 

444

 

Total Assets

 

$

104,372

 

92,861

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

Accounts payable

 

$

11,292

 

8,727

 

Accounts payable—related parties

 

605

 

404

 

Notes payable and long-term debt due within one year

 

1,125

 

632

 

Accrued income and other taxes

 

4,176

 

3,154

 

Employee benefit obligations

 

1,202

 

1,215

 

Other accruals

 

2,894

 

1,351

 

Liabilities of discontinued operations held for sale

 

104

 

103

 

Total Current Liabilities

 

21,398

 

15,586

 

Long-term debt

 

12,372

 

14,370

 

Asset retirement obligations and accrued environmental costs

 

3,752

 

3,894

 

Deferred income taxes

 

10,934

 

10,385

 

Employee benefit obligations

 

2,307

 

2,415

 

Other liabilities and deferred credits

 

2,539

 

2,383

 

Total Liabilities

 

53,302

 

49,033

 

 

 

 

 

 

 

Minority Interests

 

1,232

 

1,105

 

 

 

 

 

 

 

Common Stockholders’ Equity

 

 

 

 

 

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

 

 

 

 

 

Issued (2005—1,454,771,356 shares; 2004—1,437,729,662 shares)*

 

 

 

 

 

Par value*

 

14

 

14

 

Capital in excess of par*

 

26,712

 

26,047

 

Compensation and Benefits Trust (CBT) (at cost: 2005—47,116,283 shares; 2004—48,182,820 shares)

 

(798

)

(816

)

Treasury stock (at cost: 2005—20,090,000 shares; 2004—0 shares)

 

(1,165

)

 

Accumulated other comprehensive income

 

1,015

 

1,592

 

Unearned employee compensation

 

(277

)

(242

)

Retained earnings

 

24,337

 

16,128

 

Total Common Stockholders’ Equity

 

49,838

 

42,723

 

Total

 

$

104,372

 

92,861

 

 

 

 

 

 

 

*2004 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.

 

See Notes to Consolidated Financial Statements.

 

 

2



 

Consolidated Statement of Cash Flows

ConocoPhillips

 

 

 

Millions of Dollars

 

 

 

Nine Months Ended
September 30

 

 

 

2005

 

2004

 

Cash Flows From Operating Activities

 

 

 

 

 

Income from continuing operations

 

$

9,858

 

5,627

 

Adjustments to reconcile income from continuing operations to net cash provided by continuing operations

 

 

 

 

 

Non-working capital adjustments

 

 

 

 

 

Depreciation, depletion and amortization

 

3,075

 

2,768

 

Property impairments

 

31

 

63

 

Dry hole costs and leasehold impairments

 

211

 

342

 

Accretion on discounted liabilities

 

135

 

126

 

Deferred taxes

 

753

 

998

 

Undistributed equity earnings

 

(1,682

)

(541

)

Gain on asset dispositions

 

(264

)

(82

)

Other

 

1

 

105

 

Working capital adjustments

 

 

 

 

 

Decrease in aggregate balance of accounts receivable sold

 

(480

)

(600

)

Increase in other accounts and notes receivable

 

(1,269

)

(1,224

)

Increase in inventories

 

(1,275

)

(373

)

Increase in prepaid expenses and other current assets

 

(1,150

)

(87

)

Increase in accounts payable

 

2,748

 

1,374

 

Increase in taxes and other accruals

 

2,267

 

299

 

Net cash provided by continuing operations

 

12,959

 

8,795

 

Net cash used in discontinued operations

 

(6

)

(33

)

Net Cash Provided by Operating Activities

 

12,953

 

8,762

 

 

 

 

 

 

 

Cash Flows From Investing Activities

 

 

 

 

 

Cash consolidated from adoption and application of FIN 46

 

 

11

 

Capital expenditures and investments, including dry hole costs

 

(8,573

)

(4,659

)

Proceeds from asset dispositions

 

608

 

1,427

 

Long-term advances/loans to affiliates and other

 

(188

)

(109

)

Collection of advances/loans to affiliates and other

 

159

 

104

 

Net cash used in continuing operations

 

(7,994

)

(3,226

)

Net cash used in discontinued operations

 

 

(2

)

Net Cash Used in Investing Activities

 

(7,994

)

(3,228

)

 

 

 

 

 

 

Cash Flows From Financing Activities

 

 

 

 

 

Issuance of debt

 

333

 

290

 

Repayment of debt

 

(1,845

)

(2,594

)

Issuance of company common stock

 

377

 

269

 

Repurchase of company common stock

 

(1,165

)

 

Dividends paid on common stock

 

(1,210

)

(886

)

Other

 

87

 

117

 

Net cash used in continuing operations

 

(3,423

)

(2,804

)

Net Cash Used in Financing Activities

 

(3,423

)

(2,804

)

 

 

 

 

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

 

(120

)

43

 

 

 

 

 

 

 

Net Change in Cash and Cash Equivalents

 

1,416

 

2,773

 

Cash and cash equivalents at beginning of period

 

1,387

 

490

 

Cash and Cash Equivalents at End of Period

 

$

2,803

 

3,263

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.

 

 

 

 

 

 

3



 

 

Notes to Consolidated Financial Statements

 

ConocoPhillips

 

Note 1—Interim Financial Information

 

The interim-period financial information presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments that, in the opinion of management, are 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.  These interim financial statements should be read in conjunction with the consolidated financial statements and notes included in ConocoPhillips’ 2004 Annual Report on Form 10-K.  Certain amounts in the 2004 financial statements included in this report on Form 10-Q have been reclassified to conform to the 2005 presentation.

 

Note 2—Accounting Policies

 

Revenue Recognition—Revenues associated with sales of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.  Revenues include the sales portion of transactions commonly called buy/sell contracts, in which physical commodity purchases and sales are simultaneously contracted with the same counterparty to either obtain a different quality or grade of refinery feedstock supply, reposition a commodity (for example, where we enter into a contract with a counterparty to sell refined products or natural gas volumes at one location and purchase similar volumes at another location closer to our customer), or both.

 

Buy/sell transactions have the same general terms and conditions as typical commercial contracts including: separate title transfer, transfer of risk of loss, separate billing and cash settlement for both the buy and sell sides of the transaction, and non-performance by one party does not relieve the other party of its obligation to perform, except in events of force majeure.  Because buy/sell contracts have similar terms and conditions, we account for these purchase and sale transactions in the consolidated income statement as monetary transactions outside the scope of Accounting Principles Board (APB) Opinion No. 29.

 

Our buy/sell transactions are similar to the “barrel back” example used in Emerging Issues Task Force (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3.”  Using the “barrel back” example, the EITF concluded that a company’s decision to display buy/sell-type transactions either gross or net on the income statement is a matter of judgment that depends on relevant facts and circumstances.  We apply this judgment based on guidance in EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (Issue No. 99-19), which provides indicators for when to report revenues and the associated cost of goods sold gross (i.e., on separate revenue and cost of sales lines in the income statement) or net (i.e., on the same line).  The indicators for gross reporting in Issue No. 99-19 are consistent with many of the characteristics of buy/sell transactions, which support our accounting for buy/sell transactions.

 

We also believe that the conclusion reached by the Derivatives Implementation Group Statement 133 Implementation Issue No. K1, “Miscellaneous: Determining Whether Separate Transactions Should be Viewed as a Unit,” further supports our judgment that the purchase and sale contracts should be viewed as two separate transactions and not as a single transaction.

 

4



 

At its September 2005 meeting, the EITF reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which encompasses our buy/sell transactions described above.

 

The EITF concluded that exchanges of finished goods for raw materials or work-in-progress within the same line of business should be recorded gross at fair value because these exchanges culminate the earnings process.  Additionally, the EITF concluded that purchases and sales of inventory with the same counterparty in the same line of business should be recorded net and accounted for as nonmonetary exchanges in accordance with APB Opinion No. 29 if they are entered into “in contemplation” of one another.  The inventory could be raw materials, work-in-progress, or finished goods.

 

The new guidance is effective prospectively beginning April 1, 2006, for new arrangements entered into, and for modifications or renewals of existing arrangements.  We are reviewing this guidance and believe that any impact to income from continuing operations and net income would result from effects on last-in, first-out (LIFO) inventory valuations and would not be material to our financial statements.

 

Had this new guidance been effective for the periods reported in this Form 10-Q and depending on the determination of what transactions are affected by the new guidance, we could have been required to reduce sales and other operating revenues for the third quarters of 2005 and 2004 by $5,879 million and $3,863 million, respectively, and for the nine-month 2005 and 2004 periods by $15,284 million and $10,662 million, respectively, with related decreases in purchased crude oil, natural gas and products.

 

Our Commercial organization uses commodity derivative contracts (such as futures and options) in various markets to optimize the value of our supply chain and to balance physical systems.  In addition to cash settlement prior to contract expiration, exchange-traded futures contracts may also be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand.

 

Revenues from the production of natural gas properties, in which we have an interest with other producers, are recognized based on the actual volumes we sold during the period.  Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate.  Cumulative differences between volumes sold and entitlement volumes are generally not significant.  Revenues associated with royalty fees from licensed technology are recorded based either upon volumes produced by the licensee or upon the successful completion of all substantive performance requirements related to the installation of licensed technology.

 

Stock-Based Compensation—Effective January 1, 2003, we voluntarily adopted the fair-value accounting method prescribed by Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation.”  We used the prospective transition method, applying the fair-value accounting method and recognizing compensation expense equal to the fair-market value on the grant date for all stock options granted or modified after December 31, 2002.

 

Employee stock options granted prior to 2003 continue to be accounted for under APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations.  Because the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is generally recognized under APB Opinion No. 25.  The following table displays pro forma information as if provisions of SFAS No. 123 had been applied to all employee stock options granted:

 

5



 

 

 

Millions of Dollars

 

 

 

Three Months Ended
September 30

 

Nine Months Ended
September 30

 

 

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

Net income, as reported

 

$

3,800

 

2,006

 

9,850

 

5,697

 

Add: Stock-based employee compensation expense included in reported net income, net of related tax effects

 

71

 

27

 

144

 

66

 

Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects

 

(72

)

(29

)

(146

)

(74

)

Pro forma net income

 

$

3,799

 

2,004

 

9,848

 

5,689

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings per share*:

 

 

 

 

 

 

 

 

 

Basic—as reported

 

$

2.73

 

1.45

 

7.05

 

4.13

 

Basic—pro forma

 

2.73

 

1.45

 

7.05

 

4.13

 

Diluted—as reported

 

2.68

 

1.43

 

6.94

 

4.08

 

Diluted—pro forma

 

2.68

 

1.43

 

6.94

 

4.07

 

*Per-share amounts reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.

 

 

Note 3—Common Stock Split

 

On April 7, 2005, our Board of Directors declared a 2-for-1 common stock split effected in the form of a 100 percent stock dividend, payable June 1, 2005, to stockholders of record as of May 16, 2005.  The total number of authorized common shares and associated par value per share were unchanged by this action.  Shares and per-share information in the Consolidated Income Statement and Balance Sheet are on an after-split basis for all periods presented.

 

Note 4—Changes in Accounting Principles

 

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 153, “Exchange of Nonmonetary Assets, an amendment of APB Opinion No. 29.”  This amendment eliminates the APB Opinion No. 29 exception for fair value recognition of nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance.  We adopted this guidance on a prospective basis effective July 1, 2005.  There was no impact to our financial statements upon adoption.

 

In June 2005, the FASB ratified EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (Issue No. 04-5).  Issue No. 04-5 adopts a framework for evaluating whether the general partner (or general partners as a group) controls the partnership.  The framework makes it more likely that a single general partner (or a general partner within a general partner group) would have to consolidate the limited partnership regardless of its ownership in the limited partnership.  The new guidance was effective upon ratification for all newly formed limited partnerships and for existing limited partnership agreements that are modified.  The adoption of this portion of the EITF guidance had no impact on our financial statements.  The guidance is effective January 1, 2006, for existing limited partnership agreements that have not been modified.  We are reviewing Issue No. 04-5 to determine the impact, if any, on our financial statements.

 

6



 

In April 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1, “Accounting for Suspended Well Costs” (FSP FAS 19-1), with application required in the first reporting period beginning after April 4, 2005.  Under early application provisions, we adopted FSP FAS 19-1 effective January 1, 2005.  The adoption of this standard did not impact nine-month 2005 net income.  See Note 8—Properties, Plants and Equipment for additional information.

 

In December 2004, the FASB issued FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” and FSP 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (FSP FAS 109-1 and 109-2).  See Note 20—Income Taxes for additional information.

 

Consolidation of Variable Interest Entities (VIEs)

In February 2003, we entered into two 20-year agreements establishing separate guarantee facilities of $50 million each for two liquefied natural gas ships that were under construction.  Subject to the terms of the facilities, we will be required to make payments should the charter revenue generated by the ships fall below a certain specified minimum threshold, and we will receive payments to the extent that such revenues exceed those thresholds.  Actual gross payments over the 20 years could exceed $100 million to the extent cash is received by us.  In the first quarter of 2004, we determined the entity associated with the first ship was a VIE, but we were not the primary beneficiary and did not consolidate the entity.  The second ship was delivered to its owner in July 2005.  In the third quarter of 2005, we received the required information related to the entity associated with the second ship and determined that it is a VIE; however, we are not the primary beneficiary and therefore we will not consolidate the entity.  We currently account for these agreements as guarantees and contingent liabilities.  See Note 12—Guarantees for additional information.

 

In July 2004, we announced the finalization of our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in an LNG receiving terminal in Quintana, Texas.  We have no ownership in Freeport LNG; however, we obtained a 50 percent interest in Freeport LNG GP, Inc., which serves as the general partner managing the venture.  We entered into a credit agreement with Freeport LNG, whereby we will provide loan financing of approximately $600 million for the construction of the terminal.  Through September 30, 2005, we had provided $148 million in financing.  We determined that Freeport LNG is a VIE, and that we are not the primary beneficiary.  We account for our loan to Freeport LNG as a financial asset.

 

On June 30, 2005, ConocoPhillips and LUKOIL created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the northwest Arctic region of Russia.  We determined that NMNG is a VIE because we and our related party, LUKOIL, have disproportionate interests.  We have a 30 percent ownership interest with a 50 percent governance interest in the joint venture.  We use the equity method of accounting for this investment because we have determined we are not the primary beneficiary.  Our funding for a 30 percent ownership interest amounted to $512 million.  This acquisition price was based on preliminary estimates of capital expenditures and working capital.  Purchase price adjustments are expected to be finalized by the end of the year.  At September 30, 2005, the book value of our investment in the venture was $567 million.

 

Production from the NMNG joint-venture fields is transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL is expected to complete an expansion of the terminal's capacity in 2007, with ConocoPhillips participating in the design and financing of the expansion.  We determined that the terminal entity, Varandey Terminal Company, is also a VIE because we and our related party, LUKOIL, have disproportionate interests.  We

 

7



 

have an obligation to fund, through loans, 30 percent of the terminal’s costs, but we will have no governance or ownership interest in the terminal.  We have determined that we are not the primary beneficiary and account for our loan to Varandey Terminal Company as a financial asset.  Through September 30, 2005, we had provided $48 million in loan financing.

 

Note 5—Discontinued Operations

 

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

 

 

 

Millions of Dollars

 

 

 

Three Months Ended
September 30

 

Nine Months Ended
September 30

 

 

 

2005

 

2004

 

2005

 

2004

 

Sales and other operating revenues from discontinued operations

 

$

115

 

105

 

280

 

1,024

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from discontinued operations before-tax

 

$

(6

)

(7

)

(12

)

96

 

Income tax expense (benefit)

 

(2

)

(2

)

(4

)

26

 

Income (loss) from discontinued operations

 

$

(4

)

(5

)

(8

)

70

 

 

 

 

 

 

 

 

 

 

 

 

Assets of discontinued operations were primarily properties, plants and equipment, while liabilities of discontinued operations were primarily deferred taxes.

 

Note 6—Inventories

 

Inventories consisted of the following:

 

 

 

Millions of Dollars

 

 

 

September 30

 

December 31

 

 

 

2005

 

2004

 

 

 

 

 

 

 

Crude oil and petroleum products

 

$

4,272

 

3,147

 

Materials, supplies and other

 

566

 

519

 

 

 

$

4,838

 

3,666

 

 

 

 

 

 

 

 

Inventories valued on a LIFO basis totaled $4,117 million and $2,988 million at September 30, 2005, and December 31, 2004, respectively.  The remainder of our inventories is valued under various methods, including first-in, first-out and weighted average.  The excess of current replacement cost over LIFO cost of inventories amounted to $5,078 million and $2,220 million at September 30, 2005, and December 31, 2004, respectively.

 

8



 

Note 7—Investments and Long-Term Receivables

 

LUKOIL

During the third quarter of 2005, we increased our ownership interest in LUKOIL to 14.8 percent at September 30, 2005, from 12.6 percent at June 30, 2005, and 10 percent at December 31, 2004.

 

At September 30, 2005, the book value of our ordinary share investment in LUKOIL was $4,740 million. Our 14.8 percent share of the net assets of LUKOIL was estimated to be $3,627 million.  This basis difference of $1,113 million is primarily being amortized on a unit-of-production basis.  On September 30, 2005, the closing price of LUKOIL shares on the London Stock Exchange was $57.82 per share, making the aggregate total market value of our LUKOIL investment $7,290 million at that date.

 

Duke Energy Field Services, LLC (DEFS)

In July 2005, ConocoPhillips and Duke Energy Corporation (Duke) completed the restructuring of their respective ownership levels in DEFS, which resulted in DEFS becoming a jointly controlled venture, owned 50 percent by each company.  This restructuring increased our ownership in DEFS to 50 percent from 30.3 percent through a series of direct and indirect transfers of certain Canadian Midstream assets from DEFS to Duke, a disproportionate cash distribution from DEFS to Duke from the sale of DEFS’ interest in TEPPCO Partners, L.P., and a combined payment by ConocoPhillips to Duke and DEFS of approximately $840 million.  This payment was approximately $230 million higher than previously anticipated because our interest in the Empress plant in Canada was not included in the initial transaction as anticipated due to weather-related damages to the facility.  Subsequently the Empress plant was sold to Duke on August 1, 2005, for approximately $230 million.

 

In the first quarter of 2005, as a part of equity earnings, we recorded our $306 million (after-tax) equity share of the financial gain from DEFS’ sale of its interest in TEPPCO.

 

At September 30, 2005, the book value of our investment in DEFS was $1,490 million.  Our 50 percent share of the net assets of DEFS was $1,470 million.  This basis difference of $20 million is primarily being amortized on a straight-line basis through 2014 consistent with the remaining estimated useful lives of DEFS’ properties, plants and equipment.

 

Note 8—Properties, Plants and Equipment

 

Properties, plants and equipment included the following:

 

 

 

Millions of Dollars

 

 

 

September 30

 

December 31

 

 

 

2005

 

2004

 

 

 

 

 

 

 

Properties, plants and equipment

 

$

73,177

 

69,151

 

Accumulated depreciation, depletion and amortization

 

(20,695

)

(18,249

)

Net properties, plants and equipment

 

$

52,482

 

50,902

 

 

 

 

 

 

 

 

Suspended Wells

In April 2005, the FASB issued FSP FAS 19-1, “Accounting for Suspended Well Costs” (FSP FAS 19-1). This FASB Staff Position was issued to address whether there were circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when further exploratory drilling is planned and major capital expenditures would be required to develop the project.

 

9



 

FSP FAS 19-1 requires the continued capitalization of suspended well costs if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing these reserves and the economic and operating viability of the project.  All relevant facts and circumstances should be evaluated in determining whether a company is making sufficient progress assessing the reserves, and FSP FAS 19-1 provides several indicators to assist in this evaluation.  FSP FAS 19-1 prohibits continued capitalization of suspended well costs on the chance that market conditions will change or technology will be developed to make the project economic.  We adopted FSP FAS 19-1 effective January 1, 2005.  There was no impact to our consolidated financial statements from the adoption.

 

The following table reflects the net changes in suspended exploratory well costs during the first nine months of 2005, as well as for the years 2004 and 2003.

 

 

 

Millions of Dollars

 

 

 

Nine Months Ended
September 30, 2005

 

Year
2004

 

Year
2003

 

 

 

 

 

 

 

 

 

Beginning balance at January 1

 

$

347

 

403

 

221

 

 

 

 

 

 

 

 

 

Additions pending the determination of proved reserves

 

106

 

142

 

217

 

Reclassifications to proved properties

 

(73

)

(112

)

(6

)

Charged to dry hole expense

 

(83

)

(86

)

(29

)

Ending balance

 

$

297

 

347

 

403

 

 

 

 

 

 

 

 

 

 

The following table provides an aging of suspended well balances at September 30, 2005, and December 31, 2004 and 2003:

 

 

 

Millions of Dollars

 

 

 

September 30

 

December 31

 

 

 

2005

 

2004

 

2003

 

Exploratory well costs capitalized for a period of one year or less

 

$

142

 

142

 

217

 

Exploratory well costs capitalized for a period greater than one year

 

155

 

205

 

186

 

Ending balance

 

$

297

 

347

 

403

 

 

 

 

 

 

 

 

 

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year

 

15

 

16

 

12

 

 

10



 

The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of September 30, 2005:

 

 

 

Millions of Dollars

 

 

 

Suspended Since

 

Project

 

Total

 

2004

 

2003

 

2002

 

200l

 

 

 

 

 

 

 

 

 

 

 

 

 

Alpine satellite-Alaska (1)

 

$

21

 

 

 

21

 

 

Foothills of Western Alberta—Canada (3)

 

20

 

20

 

 

 

 

Kashagan—Republic of Kazakhstan (2)

 

18

 

 

9

 

 

9

 

Kairan—Republic of Kazakhstan (2)

 

14

 

14

 

 

 

 

Aktote—Republic of Kazakhstan (4)

 

12

 

 

12

 

 

 

Gumusut—Malaysia (4)

 

12

 

 

12

 

 

 

Bohai Bay satellites—China (4)

 

12

 

5

 

7

 

 

 

Eight projects of less than $10 million each (2)(4)

 

46

 

3

 

21

 

14

 

8

 

Total of 15 projects

 

$

155

 

42

 

61

 

35

 

17

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)       Development decisions pending infrastructure west of Alpine and construction authorization.

(2)       Additional appraisal wells planned.

(3)       Wells in various stages of testing/completion.

(4)       Appraisal drilling complete; costs being incurred to assess development.

 

Note 9—Property Impairments

 

During 2005 and 2004, we recorded property impairments related to planned asset dispositions.  The amount of property impairments by segment were:

 

 

 

Millions of Dollars

 

 

 

Three Months Ended
September 30

 

Nine Months Ended
September 30

 

 

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

Exploration and Production

 

$

 

2

 

1

 

10

 

Midstream

 

 

 

30

 

36

 

Refining and Marketing

 

 

10

 

 

17

 

 

 

$

 

12

 

31

 

63

 

 

 

 

 

 

 

 

 

 

 

 

Note 10—Debt

 

At September 30, 2005, we had two revolving credit facilities totaling $5 billion, available for use either as direct bank borrowings or as support for the issuance of up to $5 billion in commercial paper, a portion of which could be denominated in other currencies (limited to euro 3 billion equivalent).  The facilities included a $2.5 billion four-year facility expiring in October 2008 and a $2.5 billion five-year facility expiring in October 2009.  In addition, the five-year facility could be used to support issuances of letters of credit totaling up to $750 million.  The facilities were broadly syndicated among financial institutions and did not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings.  The credit agreements did contain a cross-default provision relating to our, or any of our consolidated subsidiaries’, failure to pay principal or interest on other debt obligations of $200 million or more.  At September 30, 2005, and December 31, 2004, we had no outstanding borrowings under these facilities, but $62 million and $173 million, respectively, in letters of credit had been issued.  There was no commercial paper outstanding at September 30, 2005, compared with $544 million at December 31, 2004.

 

11



 

On October 5, 2005, we replaced the two revolving credit facilities discussed above with two new revolving credit facilities totaling $5 billion.  Both facilities expire in October 2010, contain the same provisions as the previous facilities and are available for use as direct bank borrowings or as support for our $5 billion commercial paper program.

 

In March 2005, we redeemed our $400 million 3.625% Notes due 2007 at par, plus accrued interest.  In conjunction with this redemption, $400 million of interest rate swaps were cancelled.

 

During the third quarter, we purchased, at market prices, and retired $454 million of various ConocoPhillips bond issues.  These purchases resulted in after-tax losses of $42 million.  In October 2005, we gave notice to redeem the $750 million aggregate principal amount of our 6.35% Notes due 2009 in November 2005.  In conjunction with this redemption, $750 million of interest rate swaps will be cancelled.

 

Note 11—Contingencies and Commitments

 

In the case of all known contingencies, we accrue a liability when the loss is probable and the amount is reasonably estimable.  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.

 

As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.  Estimates that are 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 federal, state and local environmental laws and regulations.  These may result in obligations 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 sites.  When we prepare our 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 consideration the likely effects of societal and economic factors.  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 also consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they become both probable and reasonably estimable.

 

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for 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 of the cleanup costs related to any site at which we have been designated as a potentially responsible party.  If we were solely responsible, the costs, in some cases, could be material to our, or one of our segments’, results of operations, capital resources or liquidity.  However, settlements and costs incurred in matters that previously have been resolved have not been material to our results of operations or financial condition.  We have been successful to date in sharing cleanup costs with other financially sound companies.  Many of

 

12



 

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 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 have not recorded accruals for any potential contingent liabilities that we expect to be funded by the prior owners under these indemnifications.

 

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 for those assumed in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated.  At September 30, 2005, our balance sheet included a total environmental accrual of $996 million, compared with $1,061 million at December 31, 2004.  We expect to incur the majority 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—We apply our 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 trial settings, as well as the status and pace of settlement discussions in individual matters.  Based on our professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, we believe that there is only a remote likelihood 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 financial statements.

 

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, we have performance obligations that are secured by unused letters of credit and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

 

Note 12—Guarantees

 

At September 30, 2005, 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, no liability has been recorded for the guarantee.

 

13



 

Construction Completion Guarantees

 

                  We have a construction completion guarantee related to our share of the debt held by Hamaca Holding LLC, which was used to construct the joint-venture project in Venezuela.  The maximum potential amount of future payments under the guarantee is estimated to be $370 million. The original Guaranteed Project Completion Date of October 1, 2005, has been extended to December 31, 2005, because of force majeure events that occurred during the construction period. The guarantee therefore remains in place, and can be called due if completion certification is not achieved by the revised date. Outstanding certification requirements may be resolved satisfactorily so that completion certification can be achieved; however, it remains possible that the construction completion guarantee may not be fully released or the debt could be called due if the issues are not satisfactorily resolved.

 

Guarantees of Joint-Venture Debt

 

                  At September 30, 2005, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 20 years.  The maximum potential amount of future payments under the guarantees is approximately $230 million.  Payment would be required if a joint venture defaults on its debt obligations.  Included in these outstanding guarantees was $98 million associated with the Polar Lights Company joint venture in Russia.

 

Other Guarantees

 

                  The Merey Sweeny, L.P. (MSLP) joint-venture project agreement requires the partners in the venture to pay cash calls to cover operating expenses in the event that the venture does not have enough cash to cover operating expenses after setting aside the amount required for debt service over the next 19 years.  Although there is no maximum limit stated in the agreement, the intent is to cover short-term cash deficiencies should they occur.  Our maximum potential future payments under the agreement are currently estimated to be $100 million, assuming such a shortfall exists at some point in the future due to an extended operational disruption.  If such an operational disruption did occur, MSLP has business interruption insurance and would be entitled to insurance proceeds, subject to deductibles and certain limits.

 

                  In February 2003, we entered into two agreements establishing separate guarantee facilities for $50 million each for two liquefied natural gas ships.  Subject to the terms of each such facility, we will be required to make payments should the charter revenue generated by the respective ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds.  The net maximum future payments that we may have to make over the 20-year terms of the two agreements could be up to an aggregate of $100 million.  Actual gross payments over the 20 years could exceed that amount to the extent cash is received by us.  In the event either ship is sold or a total loss occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities.  See Note 4—Changes in Accounting Principles for additional information.

 

                  We have other guarantees with maximum future potential payment amounts totaling $320 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, a guarantee to fund the short-term cash liquidity deficits of a lubricants joint venture, a guaranteed revenue deficiency payment to a pipeline joint venture, two small construction completion guarantees, a guarantee supporting a lease assignment on a corporate aircraft, a guarantee associated with a pending lawsuit and guarantees of the lease payment obligations of a joint venture.  The carrying amount recorded for these other guarantees, as of September 30, 2005, was $23 million.  These guarantees generally extend up to 15 years and payment would only be required if the dealer, jobber or lessee goes into default, if the lubricants joint venture has cash

 

14



 

liquidity issues, if the pipeline joint venture has revenue below a certain threshold, if construction projects are not completed, if guaranteed parties default on lease payments, or if an adverse decision occurs in the lawsuit.

 

Indemnifications

 

Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures and sold several assets, including FTC-mandated sales of downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites, giving 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 maximum amount of future payments is generally unlimited.  The carrying amount recorded for these indemnifications, as of September 30, 2005, was $452 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 that 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 that 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 carrying amount recorded were $338 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at September 30, 2005.  For additional information about environmental liabilities, see Note 11—Contingencies and Commitments.

 

Note 13—Financial Instruments and Derivative Contracts

 

Derivative assets and liabilities were:

 

 

 

Millions of Dollars

 

 

 

September 30

 

December 31

 

 

 

2005

 

2004

 

Derivative Assets

 

 

 

 

 

Current

 

$

1,177

 

437

 

Long-term

 

199

 

42

 

 

 

$

1,376

 

479

 

 

 

 

 

 

 

Derivative Liabilities

 

 

 

 

 

Current

 

$

1,401

 

265

 

Long-term

 

332

 

57

 

 

 

$

1,733

 

322

 

 

 

 

 

 

 

 

In June 2005, we acquired two limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our natural gas production.  As part of the acquisition, we assumed related commodity swaps with a negative fair value of $261 million at June 30, 2005.  In late June and early July, we entered into additional commodity swaps to offset essentially all of the exposure from the assumed swaps.  At September 30, 2005, the commodity swaps assumed in the acquisition had a negative fair value of $424 million, and the commodity swaps entered to offset the resulting exposure had a positive fair value

 

15



 

of $187 million.  Although these commodity swaps contributed to the increase in derivative assets and liabilities from December 31, 2004, to September 30, 2005, price movements, particularly price increases in natural gas, during the third quarter were primarily responsible for the increase.

 

Note 14—Comprehensive Income

 

ConocoPhillips’ comprehensive income was as follows:

 

 

 

Millions of Dollars

 

 

 

Three Months Ended
September 30

 

Nine Months Ended
September 30

 

 

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

3,800

 

2,006

 

9,850

 

5,697

 

After-tax changes in:

 

 

 

 

 

 

 

 

 

Minimum pension liability adjustment

 

 

 

(1

)

(1

)

Foreign currency translation adjustments

 

13

 

132

 

(579

)

156

 

Unrealized loss on securities

 

 

 

(1

)

 

Hedging activities

 

(1

)

(3

)

4

 

2

 

 

 

$

3,812

 

2,135

 

9,273

 

5,854

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

Millions of Dollars

 

 

 

September 30
2005

 

December 31
2004

 

 

 

 

 

 

 

Minimum pension liability adjustment

 

$

(68

)

(67

)

Foreign currency translation adjustments

 

1,083

 

1,662

 

Unrealized gain on securities

 

5

 

6

 

Deferred net hedging loss

 

(5

)

(9

)

 

 

$

1,015

 

1,592

 

 

 

 

 

 

 

 

Note 15—Supplemental Cash Flow Information

 

 

 

Millions of Dollars

 

 

 

Nine Months Ended
September 30

 

 

 

2005

 

2004

 

Non-Cash Investing and Financing Activities

 

 

 

 

 

Investment in properties, plants and equipment of businesses through the assumption of non-cash liabilities*

 

$

261

 

 

Fair market value of properties, plants and equipment received in a nonmonetary exchange transaction

 

138

 

 

Cash Payments

 

 

 

 

 

Interest

 

$

300

 

324

 

Income taxes

 

4,996

 

2,791

 

*See Note 13—Financial Instruments and Derivative Contracts for additional information.

 

 

 

 

 

 

16



 

Note 16—Sales of Receivables

 

At December 31, 2004, certain credit card and trade receivables had been sold to a Qualifying Special Purpose Entity (QSPE) in a revolving-period securitization arrangement.  The arrangement provided for ConocoPhillips to sell, and the QSPE to purchase, certain receivables and for the QSPE to then issue beneficial interests of up to $1.2 billion to five bank-sponsored entities.  At December 31, 2004, the QSPE had issued beneficial interests to the bank-sponsored entities of $480 million.  All five bank-sponsored entities are multi-seller conduits with access to the commercial paper market and purchase interests in similar receivables from numerous other companies unrelated to us.  We have held no ownership interests, nor any variable interests, in any of the bank-sponsored entities, which we have not consolidated.  Furthermore, except as discussed below, we have not consolidated the QSPE because it has met the requirements of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” to be excluded from the consolidated financial statements of ConocoPhillips.  The receivables transferred to the QSPE have met the isolation and other requirements of SFAS No. 140 to be accounted for as sales and have been accounted for accordingly.

 

By January 31, 2005, all of the beneficial interests held by the bank-sponsored entities had matured; therefore, in accordance with SFAS No. 140, the operating results and cash flows of the QSPE subsequent to this maturity have been consolidated in our financial statements, and the assets and liabilities of the QSPE have been included in our September 30, 2005, balance sheet.  The revolving-period securitization arrangement was terminated on August 31, 2005, and, at this time, we have no plans to renew the arrangement.

 

Total cash flows received from, and paid under, the securitization arrangements were as follows:

 

 

 

Millions of Dollars

 

 

 

2005

 

2004

 

 

 

 

 

 

 

Receivables sold at beginning of year

 

$

480

 

1,200

 

New receivables sold

 

960

 

6,075

 

Cash collections remitted

 

(1,440

)

(6,675

)

Receivables sold at September 30

 

$

 

600

 

 

 

 

 

 

 

Discounts and other fees paid on revolving balances

 

$

2

 

5

 

 

 

 

 

 

 

 

Note 17—Employee Benefit Plans

 

Pension and Postretirement Plans

 

 

 

Millions of Dollars

 

 

 

Pension Benefits

 

Other Benefits

 

Three Months Ended

 

September 30

 

September 30

 

 

 

2005

 

2004

 

2005

 

2004

 

 

 

U.S.

 

Int’l.

 

U.S.

 

Int’l.

 

 

 

 

 

Components of Net Periodic Benefit Cost

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

37

 

16

 

38

 

18

 

5

 

6

 

Interest cost

 

43

 

30

 

44

 

28

 

12

 

15

 

Expected return on plan assets

 

(31

)

(26

)

(26

)

(23

)

 

 

Amortization of prior service cost

 

1

 

2

 

1

 

2

 

5

 

4

 

Recognized net actuarial loss (gain)

 

14

 

8

 

13

 

9

 

(2

)

2

 

Net periodic benefit costs

 

$

64

 

30

 

70

 

34

 

20

 

27

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

17



 

 

 

Millions of Dollars

 

 

 

Pension Benefits

 

Other Benefits

 

Nine Months Ended

 

September 30

 

September 30

 

 

 

2005

 

2004

 

2005

 

2004

 

 

 

U.S.

 

Int’l.

 

U.S.

 

Int’l.

 

 

 

 

 

Components of Net Periodic Benefit Cost

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

113

 

53

 

113

 

52

 

15

 

17

 

Interest cost

 

130

 

94

 

131

 

83

 

37

 

44

 

Expected return on plan assets

 

(94

)

(82

)

(78

)

(68

)

 

 

Amortization of prior service cost

 

3

 

6

 

3

 

5

 

15

 

14

 

Recognized net actuarial loss (gain)

 

41

 

25

 

39

 

29

 

(4

)

7

 

Net periodic benefit costs

 

$

193

 

96

 

208

 

101

 

63

 

82

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

We recognized pension settlement losses of $2 million and $9 million in the first nine months of 2005 and 2004, respectively.  Of these amounts, $2 million and $1 million were recognized in the third quarters of 2005 and 2004, respectively.

 

During the first nine months of 2005, we contributed $368 million to our domestic qualified and non-qualified benefit plans and $112 million to international qualified and non-qualified benefit plans.

 

At the end of 2004, we estimated that, during 2005, we would contribute approximately $410 million to our domestic qualified and non-qualified benefit plans and $140 million to our international benefit plans.  We presently anticipate contributing $540 million to our domestic plans and $150 million to our international plans in 2005.

 

During the third quarter, we announced that retail prescription drug coverage will be extended to heritage Phillips retirees, similar to the benefit provided to heritage Conoco and Tosco retirees.  Because of this change, we measured our postretirement medical plan liability as of September 1, 2005.  Also included in the September 1, 2005, measurement was a loss from lowering the discount rate by 75 basis points to 5.00 percent, a gain from favorable claims experience, and a gain from recognizing the non-taxable federal subsidy we expect to receive under Medicare Part D.  In 2004, we stated that, based on the regulatory evidence available at that time, we did not believe the benefit provided under our plan would be actuarially equivalent to that offered under Medicare Part D and that we would not be entitled to receive a federal subsidy.  However, because of the extension of additional prescription drug benefits to heritage Phillips retirees, recent favorable claims experience, and the additional flexibility provided in the final regulations issued by the Department of Health and Human Services earlier this year regarding the submission of Medicare subsidy claims, we have now concluded that our plan will qualify for the subsidy.  Consequently, we reduced the Accumulated Postretirement Benefit Obligation (APBO) in the September 1, 2005,  measurement by $166 million for the federal subsidy and plan to reduce expense for the period from September through December 2005 for service cost, interest cost, and the amortization of gains by $2 million, $3 million, and $5 million, respectively.  Combining all of the changes included in the September 1, 2005, measurement, the medical plan’s APBO decreased by $53 million, and expense for the remainder of 2005 is expected to be $7 million lower than it would have been, based on the previous measurement.

 

18



 

Note 18—Related Party Transactions

 

Significant transactions with related parties were:

 

 

 

Millions of Dollars

 

 

 

Three Months Ended
September 30

 

Nine Months Ended
September 30

 

 

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

Operating revenues (a)

 

$

2,116

 

1,376

 

5,594

 

3,735

 

Purchases (b)

 

1,404

 

1,022

 

4,056

 

3,147

 

Operating expenses and selling, general and administrative expenses (c)

 

241

 

160

 

685

 

494

 

Net interest (income) expense (d)

 

10

 

2

 

29

 

(13

)

 

(a)                                  Our Exploration and Production (E&P) segment sells natural gas to Duke Energy Field Services, LLC (DEFS) and crude oil to the Malaysian Refining Company Sdn. Bhd (Melaka), among others, for processing and marketing.  Natural gas liquids, solvents and petrochemical feedstocks are sold to Chevron Phillips Chemical Company LLC (CPChem), gas oil and hydrogen feedstocks are sold to Excel Paralubes, and refined products are sold primarily to CFJ Properties and Getty Petroleum Marketing, Inc. (a subsidiary of LUKOIL).  Also, we charge several of our affiliates, including CPChem, MSLP, and Hamaca Holding LLC, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.

 

(b)                                 We purchase natural gas and natural gas liquids from DEFS and CPChem for use in our refinery processes and other feedstocks from various affiliates.  We purchase upgraded crude oil from Petrozuata C.A. and refined products from Melaka.  We also pay fees to various pipeline equity companies for transporting finished refined products and a price upgrade to MSLP for heavy crude processing.  We purchase base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.

 

(c)                                  We pay processing fees to various affiliates.  Additionally, we pay crude oil transportation fees to pipeline equity companies.

 

(d)                                 We pay and/or receive interest to/from various affiliates including, prior to consolidation, the receivables securitization QSPE.

 

Elimination amounts related to our equity percentage share of profit or loss on the above transactions were not material.

 

Note 19—Segment Disclosures and Related Information

 

We have organized our reporting structure based on the grouping of similar products and services, resulting in six operating segments:

 

1)              E&P—This segment primarily explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis.  At September 30, 2005, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Nigeria, Venezuela, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, the United Arab Emirates, Vietnam, and Russia.  The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes.

 

19



 

2)              Midstream—Through both consolidated and equity interests, this segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States, Canada and Trinidad.  The Midstream segment primarily consists of our equity investment in DEFS.  Through June 30, 2005, our equity ownership in DEFS was 30.3 percent.  In July 2005, we increased our ownership interest to 50 percent.

 

3)              R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.  At September 30, 2005, we owned 12 refineries in the United States; one in the United Kingdom; one in Ireland; and had equity interests in one refinery in Germany, two in the Czech Republic, and one in Malaysia.  The R&M segment’s U.S. and international operations are disclosed separately for reporting purposes.

 

4)              LUKOIL Investment—This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia.  In October 2004, we closed on a transaction to acquire 7.6 percent of LUKOIL’s shares held by the Russian government.  During the remainder of 2004, we increased our ownership to 10.0 percent.  During the first nine months of 2005, we further increased our ownership to 14.8 percent.

 

5)              Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis.  The Chemicals segment consists of our 50 percent equity investment in CPChem.

 

6)              Emerging Businesses—This segment encompasses the development of new businesses beyond our traditional operations.  Emerging Businesses includes new technologies related to natural gas conversion into clean fuels and related products (gas-to-liquids), technology solutions, power generation, and emerging technologies.

 

Corporate and Other includes general corporate overhead; interest income and expense; discontinued operations; certain eliminations; and various other corporate activities.  Corporate assets include all cash and cash equivalents.

 

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

 

20



 

Analysis of Results by Operating Segment

 

 

 

Millions of Dollars

 

 

 

Three Months Ended
September 30

 

Nine Months Ended
September 30

 

 

 

2005

 

2004

 

2005

 

2004

 

Sales and Other Operating Revenues

 

 

 

 

 

 

 

 

 

E&P

 

 

 

 

 

 

 

 

 

United States

 

$

8,388

 

6,138

 

22,913

 

17,351

 

International

 

5,742

 

3,429

 

14,980

 

11,136

 

Intersegment eliminations-U.S.

 

(1,069

)

(652

)

(2,960

)

(2,011

)

Intersegment eliminations-international

 

(1,204

)

(692

)

(3,196

)

(2,651

)

E&P

 

11,857

 

8,223

 

31,737

 

23,825

 

Midstream

 

 

 

 

 

 

 

 

 

Total sales

 

910

 

900

 

2,781

 

2,839

 

Intersegment eliminations

 

(216

)

(175

)

(643

)

(712

)

Midstream

 

694

 

725

 

2,138

 

2,127

 

R&M

 

 

 

 

 

 

 

 

 

United States

 

27,773

 

19,005

 

71,749

 

51,823

 

International

 

8,442

 

6,462

 

22,597

 

18,079

 

Intersegment eliminations-U.S.

 

(168

)

(98

)

(405

)

(290

)

Intersegment eliminations-international

 

(2

)

(24

)

(8

)

(25

)

R&M

 

36,045

 

25,345

 

93,933

 

69,587

 

LUKOIL Investment

 

 

 

 

 

Chemicals

 

3

 

4

 

10

 

11

 

Emerging Businesses

 

143

 

45

 

358

 

130

 

Corporate and Other

 

3

 

8

 

8

 

11

 

Consolidated Sales and Other Operating Revenues

 

$

48,745

 

34,350

 

128,184

 

95,691

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss)

 

 

 

 

 

 

 

 

 

E&P

 

 

 

 

 

 

 

 

 

United States

 

$

1,107

 

701

 

2,965

 

2,007

 

International

 

1,181

 

719

 

3,039

 

2,024

 

Total E&P

 

2,288

 

1,420

 

6,004

 

4,031

 

Midstream

 

88

 

38

 

541

 

135

 

R&M

 

 

 

 

 

 

 

 

 

United States

 

1,096

 

505

 

2,602

 

1,642

 

International

 

294

 

203

 

598

 

348

 

Total R&M

 

1,390

 

708

 

3,200

 

1,990

 

LUKOIL Investment

 

267

 

 

525

 

 

Chemicals

 

13

 

81

 

209

 

166

 

Emerging Businesses

 

 

(27

)

(16

)

(78

)

Corporate and Other

 

(246

)

(214

)

(613

)

(547

)

Consolidated Net Income

 

$

3,800

 

2,006

 

9,850

 

5,697

 

 

 

 

 

 

 

 

 

 

 

 

21



 

 

 

Millions of Dollars

 

 

 

September 30

 

December 31

 

 

 

2005

 

2004

 

Total Assets

 

 

 

 

 

E&P

 

 

 

 

 

United States

 

$

18,049

 

16,105

 

International

 

29,007

 

26,481

 

Goodwill

 

11,027

 

11,090

 

Total E&P

 

58,083

 

53,676

 

Midstream

 

2,346

 

1,293

 

R&M

 

 

 

 

 

United States

 

21,269

 

19,180

 

International

 

6,198

 

5,834

 

Goodwill

 

3,900

 

3,900

 

Total R&M

 

31,367

 

28,914

 

LUKOIL Investment

 

4,761

 

2,723

 

Chemicals

 

2,240

 

2,221

 

Emerging Businesses

 

878

 

972

 

Corporate and Other

 

4,697

 

3,062

 

Consolidated Total Assets

 

$

104,372

 

92,861

 

 

 

 

 

 

 

 

Note 20—Income Taxes

 

Our effective tax rate for the third quarter and first nine months of 2005 was 42 percent, compared with 45 percent and 44 percent for the same periods a year ago.  The change in the effective tax rate between the third quarter of 2005 and the third quarter of 2004 was due to a lower proportion of income in higher tax rate jurisdictions. The change in the effective tax rate for the first nine months of 2005, versus the same period in 2004, was due to the utilization of capital loss carryforwards that previously had a full valuation allowance, and a lower proportion of income in higher tax rate jurisdictions.  The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

 

One of the provisions of the American Jobs Creation Act of 2004 was a special deduction for qualifying manufacturing activities.  While the legislation is still undergoing clarifications, under guidance in FSP FAS 109-1, we included the estimated impact as a current benefit, which did not have a material impact on the company’s effective tax rate, and it did not have any impact on our assessment of the need for possible valuation allowances.

 

The American Jobs Creation Act of 2004 also included a special one time provision allowing earnings of foreign subsidiaries to be repatriated at a reduced U.S. income tax rate.  Final guidance clarifying the uncertain provisions of the law was published during the third quarter of 2005.  We have now completed our analysis of this provision, including the final guidance, and do not intend to change our repatriation plans.

 

22



 

Note 21—New Accounting Standards

 

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.”  Among other changes, this Statement requires retrospective application for voluntary changes in accounting principle, unless it is impractical to do so.  Guidance is provided on how to account for changes when retrospective application is impractical.  This Statement is effective on a prospective basis beginning January 1, 2006.

 

In March 2005, the FASB issued FASB Interpretation 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47).  This Interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event and if the liability’s fair value can be reasonably estimated.  If the liability’s fair value cannot be reasonably estimated, then the entity must disclose (a) a description of the obligation, (b) the fact that a liability has not been recognized because the fair value cannot be reasonably estimated, and (c) the reasons why it cannot be reasonably estimated.  FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.  We are required to implement this Interpretation in the fourth quarter of 2005 and are currently studying its provisions to determine the impact, if any, on our financial statements.

 

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123(R)), which supercedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” which we adopted at the beginning of 2003.  SFAS 123(R) prescribes the accounting for a wide range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights, and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed.  For ConocoPhillips, this Statement provided for an effective date of third-quarter 2005; however, in April 2005, the Securities and Exchange Commission approved a new rule that delayed the effective date until January 1, 2006.  We plan to adopt the provisions of this Statement January 1, 2006.  We are studying the provisions of this new pronouncement to determine the impact, if any, on our financial statements.  For more information on our adoption of SFAS No. 123 and its effect on net income, see Note 2—Accounting Policies.

 

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.”  This Statement clarifies that items, such as abnormal idle facility expense, excessive spoilage, double freight, and handling costs, be recognized as current-period charges.  In addition, the Statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities.  We are required to implement this Statement in the first quarter of 2006.  We are analyzing the provisions of this Statement to determine the effects, if any, on our financial statements.

 

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” to address the balance sheet classification of certain financial instruments that have characteristics of both liabilities and equity.  The Statement, already effective for contracts created or modified after May 31, 2003, was originally intended to become effective July 1, 2003, for all contracts existing at May 31, 2003.  However, on November 7, 2003, the FASB issued an indefinite deferral of certain provisions of SFAS No. 150.  We continue to monitor and assess the FASB’s modifications of SFAS No. 150, but do not anticipate any material impact to our financial statements.

 

23



 

At its September 2005 meeting, the EITF reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which addresses accounting issues that arise when one company both sells inventory to, and buys inventory from, another company in the same line of business.  For additional information, see the Revenue Recognition section of Note 2—Accounting Policies.

 

24



 

Supplementary Information—Condensed Consolidating Financial Information

 

We have various cross guarantees among ConocoPhillips and ConocoPhillips Company with respect to publicly held debt securities.  ConocoPhillips Company is wholly owned by ConocoPhillips.  ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities.  Similarly, 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 and ConocoPhillips Company (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).

 

                  All other non-guarantor subsidiaries of ConocoPhillips Company.

 

                  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.

 

Effective January 1, 2005, ConocoPhillips Holding Company was merged into ConocoPhillips Company.  Previously reported prior period information has been restated to reflect this reorganization of companies under common control.

 

25



 

 

 

Millions of Dollars

 

 

 

Three Months Ended September 30, 2005

 

Income Statement

 

ConocoPhillips

 

ConocoPhillips
Company

 

All Other
Subsidiaries

 

Consolidating
Adjustments

 

Total
Consolidated

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenues

 

$

 

33,262

 

15,483

 

 

48,745

 

Equity in earnings of affiliates

 

3,829

 

2,779

 

823

 

(6,559

)

872

 

Other income

 

(12

)

19

 

35

 

 

42

 

Intercompany revenues

 

7

 

757

 

2,774

 

(3,538

)

 

Total Revenues

 

3,824

 

36,817

 

19,115

 

(10,097

)

49,659

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and Expenses

 

 

 

 

 

 

 

 

 

 

 

Purchased crude oil, natural gas and products

 

 

28,558

 

9,138

 

(3,188

)

34,508

 

Production and operating expenses

 

 

1,079