Notes to Consolidated Financial Statements

Note 1 — Accounting Policies
	Consolidation Principles and Investments — Majority-owned, controlled subsidiaries are consolidated. The equity method is used to account for investments in affiliates in which the company exerts significant influence, generally having a 20 to 50 percent ownership interest. The company also uses the equity method for its 50.1 percent and 57.1 percent non-controlling interests in Petrozuata C.A. and Hamaca Holding LLC, respectively, located in Venezuela because the minority shareholders have substantive participating rights, under which all substantive operating decisions (e.g., annual budgets, major financings, selection of senior operating management, etc.) require joint approvals. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants, certain transportation assets and Canadian Syncrude mining operations are consolidated on a proportionate basis. Other securities and investments, excluding marketable securities, are generally carried at cost.
	Revenue Recognition — Revenues associated with sales of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and all other items are recorded when title passes to the customer. Revenues include the sales portion of contracts involving purchases and sales necessary to reposition supply to address location or quality or grade requirements (e.g., when the company repositions crude by entering into a contract with a counterparty to sell crude in one location and purchase it in a different location) and sales related to purchase for resale activity. Revenues from the production of natural gas properties in which the company has an interest with other producers are recognized based on the actual volumes sold by the company during the period. Any differences between volumes sold and entitlement volumes, based on the company’s net working interest, which are deemed non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are 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.
	Reclassification — Certain amounts in the 2001 and 2000 financial statements have been reclassified to conform with the 2002 presentation.
	Use of Estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from the estimates and assumptions used.
	Cash Equivalents — Cash equivalents are highly liquid short-term investments that are readily convertible to known amounts of cash and have original maturities within three months from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.
	Inventories — The company has several valuation methods for its various types of inventories and consistently uses the following methods for each type of inventory. Crude oil, petroleum products, and Canadian Syncrude inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Materials, supplies and other miscellaneous inventories are valued using the weighted-average-cost method, consistent with general industry practice. Merchandise inventories at the company’s retail marketing outlets are valued using the first-in, first-out (FIFO) retail method, consistent with general industry practice.
	Derivative Instruments — All derivative instruments are recorded on the balance sheet at fair value in either accounts and notes receivable, other assets, accounts payable, or other liabilities and deferred credits. Recognition of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives that are not used as hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge will be recorded on the balance sheet in accumulated other comprehensive income/(loss) until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings. In the consolidated statement of operations, gains and losses from derivatives that are not directly related to the company’s movement of its products are recorded in other income. Gains and losses from derivatives used for other purposes are recorded in either sales and other operating revenues, other income, or purchased crude oil and products, depending on the purpose for issuing or holding the derivative.
	Oil and Gas Exploration and Development — Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting. Property Acquisition Costs — Oil and gas leasehold acquisition costs are capitalized. Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon discovery of commercial reserves, leasehold costs are transferred to proved properties. Exploratory Costs — Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized as long as the additional exploratory work is under way or firmly planned. Development Costs — Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Depletion and Amortization — Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.
	Syncrude Mining Operations — Capitalized costs, including support facilities, include the cost of the acquisition and other capital costs incurred. Capital costs are depreciated using the unit-of-production method based on the applicable portion of proven reserves associated with each mine location and its facilities.
	Intangible Assets Other Than Goodwill — Intangible assets that have finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets that have indefinite useful lives are not amortized but are tested at least annually for impairment. The company evaluates the remaining useful lives of intangible assets not being amortized each reporting period to determine whether events and circumstances continue to support indefinite useful lives. Intangible assets are considered impaired if the fair value of the intangible asset is lower than cost. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.
	Goodwill — Goodwill is not amortized but is tested at least annually for impairment. If the fair value of a reporting unit is less than the recorded book value of the reporting unit’s assets (including goodwill), less liabilities, then a hypothetical purchase price allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount. Reporting units for purposes of goodwill impairment calculations are one level below or at the company’s operating segment level. Because quoted market prices are not available for the company’s reporting units, the fair value of the reporting units is determined based upon consideration of several factors, including observed market multiples of operating cash flows and net income, the depreciated replacement cost of tangible equipment, and/or the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets.
	Depreciation and Amortization — Depreciation and amortization of properties, plants and equipment on producing oil and gas properties, certain pipeline assets (those which are expected to have a declining utilization pattern), and on Syncrude mining operations are determined by the unit-of-production method. Depreciation and amortization of all other properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).
	Impairment of Properties, Plants and Equipment — Properties, plants and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions in the periods in which the determination of impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets — generally on a field-by-field basis for exploration and production assets, at an entire complex level for downstream assets or at a site level for retail stores. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell. The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. If the future production price risk has been hedged, the hedged price is used in the calculations for the period and quantities hedged. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. The price and cost outlook assumptions used in impairment reviews differ from the assumptions used in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities. In that disclosure, Statement of Financial Accounting Standards (SFAS) No. 69, “Disclosures about Oil and Gas Producing Activities,” requires the use of prices and costs at the balance sheet date, with no projection of future changes in those assumptions
	Maintenance and Repairs — The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Effective January 1, 2001, turnaround costs of major producing units are expensed as incurred. Prior to 2001, the estimated turnaround costs of major producing units were accrued in other liabilities over the estimated interval between turnarounds. See Note 2 — Extraordinary Items and Accounting Change for further discussion of this change in accounting method.
	Shipping and Handling Costs — The company’s Exploration and Production segment includes shipping and handling costs in production and operating expenses, while the Refining and Marketing segment records shipping and handling costs in purchased crude oil and products.
	Advertising Costs — Production costs of media advertising are deferred until the first public showing of the advertisement. Advances to secure advertising slots at specific sports, racing or other events are deferred until the event occurs. All other advertising costs are expensed as incurred, unless the cost has benefits which clearly extend beyond the interim period in which the expenditure is made, in which case the advertising cost is deferred and amortized ratably over the interim periods which clearly benefit from the expenditure. By the end of the fiscal year, all such interim deferred advertising costs are fully amortized to expense.
	Property Dispositions — When complete units of depreciable property are retired or sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
	Dismantlement, Removal and Environmental Costs — Through December 31, 2002, the estimated undiscounted costs, net of salvage values, of dismantling and removing major oil and gas production and transportation facilities, including necessary site restoration, were accrued using either the unit-of-production or the straight-line method, which was used for certain regional production transportation assets that are expected to have a straight-line utilization pattern. Effective January 1, 2003, the company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” See Note 27 — New Accounting Standards. Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (unless acquired in a purchase business acquisition) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is probable.
	Stock Compensation — Through December 31, 2002, the company accounted for stock options using the intrinsic value method as prescribed by the Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Pro forma information regarding changes in net income and earnings per share data (as if the accounting prescribed by SFAS No. 123, “Accounting for Stock-Based Compensation,” had been applied) is presented in Note 20 — Employee Benefit Plans. Effective January 1, 2003, the company voluntarily adopted SFAS No. 123 prospectively. See Note 20 — Employee Benefit Plans.
	Foreign Currency Translation — Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive loss in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Most of the company’s foreign operations use their local currency as the functional currency.
	Income Taxes — Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial-reporting basis and the tax basis of the company’s assets and liabilities, except for deferred taxes on income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes.
	Net Income Per Share of Common Stock — Basic income per share of common stock is calculated based upon the daily weighted-average number of common shares outstanding during the year, including shares held by the Long-Term Stock Savings Plan (LTSSP). Diluted income per share of common stock includes the above, plus “in-the-money” stock options issued under company compensation plans. Treasury stock and shares held by the Compensation and Benefits Trust (CBT) are excluded from the daily weighted-average number of common shares outstanding in both calculations.
	Capitalized Interest — Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

Note 2 — Extraordinary Items and Accounting Change
During 2002, the company incurred extraordinary losses totaling $16 million after-tax ($24 million before-tax) on the following items:

	the call premium on the early retirement of the company’s $250 million 8.86% notes due May 15, 2022;
	the redemption of the company’s outstanding 8.24% Junior Subordinated Deferrable Interest Debentures due 2036, which triggered the redemption of the $300 million of 8.24% Trust Originated Preferred Securities of Phillips 66 Capital Trust I; and
	the call premium on the early retirement of the company’s $171 million 7.443% notes due 2004.

In 2001, ConocoPhillips incurred an extraordinary loss of $10 million after-tax ($14 million before-tax) attributable to the call premium on the early retirement of its $300 million 9.18% notes due September 15, 2021.

Effective January 1, 2001, the company changed its method of accounting for the costs of major maintenance turnarounds from the accrue-in-advance method to the expense-as-incurred method to reflect the impact of a turnaround in the period that it occurs. The new method is preferable because it results in the recognition of costs at the time obligations are incurred. The cumulative effect of this accounting change increased net income in 2001 by $28 million (after reduction for income taxes of $15 million).

The pro forma effects of retroactive application of the change in accounting method are presented below:

Note 3 — Merger of Conoco and Phillips
On August 30, 2002, Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips (the merger). As a result, each company became a wholly owned subsidiary of ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer of Conoco, and ConocoPhillips was treated as the successor of Phillips.

Immediately after the closing of the merger, former Phillips stockholders held approximately 56 percent of the outstanding shares of ConocoPhillips common stock, while former Conoco stockholders held approximately 44 percent. ConocoPhillips common stock, listed on the New York Stock Exchange under the symbol “COP,” began trading on September 3, 2002.

The primary reasons for the merger and the principal factors that contributed to an accounting treatment that resulted in the recognition of goodwill were:

	the combination of Conoco and Phillips would create a stronger, major, integrated oil company with the benefits of increased size and scale, improving the stability of the combined business’ earnings in varying economic and market climates;
	ConocoPhillips would emerge with a global presence in both upstream and downstream petroleum businesses, increasing its overall international presence to over 40 countries while maintaining a strong domestic base; and
	combining the two companies’ operations would provide significant synergies and related cost savings, and improve future access to capital.

The $16 billion purchase price attributed to Conoco for accounting purposes was based on an exchange of Conoco shares for ConocoPhillips common shares. ConocoPhillips issued approximately 293 million shares of common stock and approximately 23.3 million of employee stock options in exchange for 627 million shares of Conoco common stock and 49.8 million Conoco stock options. The common stock was valued at $53.15 per share, which was Phillips’ average common stock price over the two-day trading period immediately before and after the November 18, 2001, public announcement of the transaction. The Conoco stock options, the fair value of which was determined using the Black-Scholes option-pricing model, were exchanged for ConocoPhillips stock options valued at $384 million. Transaction-related costs, included in the purchase price, were $82 million. 

The preliminary allocation of the purchase price to specific assets and liabilities was based, in part, upon an outside appraisal of the fair value of Conoco’s assets. Over the next few months ConocoPhillips expects to receive the final outside appraisal of the long-lived assets and conclude the fair value determination of all other Conoco assets and liabilities. Subsequent to completion of the final allocation of the purchase price and the determination of the ultimate asset and liability tax bases, the deferred tax liabilities will also be finalized. The following table summarizes, based on the year-end preliminary purchase price allocation, the fair values of the assets acquired and liabilities assumed as of August 30, 2002:

The allocation of the purchase price, as reflected above, has not been adjusted for the U.S. Federal Trade Commission (FTC)-mandated dispositions described in Note 4 — Discontinued Operations. Goodwill, land and certain identifiable intangible assets recorded in the acquisition are not subject to amortization, but the goodwill and intangible assets will be tested periodically for impairment as required by SFAS No. 142, “Goodwill and Other Intangible Assets.”

Of the $661 million allocated to intangible assets, $545 million is assigned to marketing tradenames which are not subject to amortization. Of the remaining value assigned to intangible assets, $66 million assigned to refining technology will be amortized over 11 years and $50 million was allocated to other intangible assets with a weighted-average amortization period of 11 years.

ConocoPhillips has not yet determined the assignment of Conoco goodwill to specific reporting units. Currently, Conoco goodwill is being reported as part of the Corporate and Other reporting segment. Of the $12,079 million of goodwill, $4,302 million is attributable to the gross-up required under purchase accounting for deferred taxes. This and the remaining “true” goodwill, or $7,777 million, will ultimately be assigned to reporting units based on the benefits received by the units from the synergies and strategic advantages of the merger. None of the goodwill is deductible for tax purposes.

The purchase price allocation included $246 million of in-process research and development costs related to Conoco’s natural gas-to-liquids and other technologies. In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 4, “Applicability of FASB Statement No. 2 to Business Combinations Accounted for by the Purchase Method,” the value assigned to the research and development activities was charged to production and operating expenses in the Emerging Businesses segment at the date of the consummation of the merger, as these research and development costs had no alternative future use.

Merger-related items that reduced ConocoPhillips’ 2002 income from continuing operations were:

In total, these items reduced 2002 income from continuing operations by $557 million ($1.15 per share on a diluted basis).

The following pro forma summary presents information as if the merger had occurred at the beginning of each period presented, and includes the $557 million effect of the merger-related items mentioned above.

During 2001, both Phillips and Conoco entered into other significant transactions that are not reflected in the companies’ historical income statements for the full year 2001. The pro forma results have been prepared as if the Phillips’ September 14, 2001, acquisition of Tosco Corporation (Tosco) (see Note 6 — Acquisition of Tosco Corporation) and Conoco’s July 16, 2001, $4.6 billion acquisition of Gulf Canada Resources Limited occurred on January 1, 2001. Gulf Canada Resources Limited was a Canadian-based independent exploration and production company with primary operations in Western Canada, Indonesia, the Netherlands and Ecuador.

The pro forma results reflect the following:

	recognition of depreciation and amortization based on the preliminary allocated purchase price of the properties, plants and equipment acquired;
	adjustment of interest for the amortization of the fair-value adjustment to debt;
	cessation of the amortization of deferred gains not recognizable in the purchase price allocation;
	accretion of discount on environmental accruals recorded at net present value; and
	various other adjustments to conform Conoco’s accounting policies to ConocoPhillips’.

The pro forma adjustments use estimates and assumptions based on currently available information. Management believes that the estimates and assumptions are reasonable, and that the significant effects of the transactions are properly reflected.

The pro forma information does not reflect any anticipated synergies that might be achieved from combining the operations. The pro forma information is not intended to reflect the actual results that would have occurred had the companies been combined during the periods presented. This pro forma information is not intended to be indicative of the results of operations that may be achieved by ConocoPhillips in the future.

Note 4 — Discontinued Operations
During 2002, the company disposed of, or had committed to a plan to dispose of, U.S. retail and wholesale marketing assets, U.S. refining and related assets, and exploration and production assets in the Netherlands. Certain of these planned dispositions were mandated by the FTC as a condition of the merger. For reporting purposes, these operations are classified as discontinued operations, and in Note 26 — Segment Disclosures and Related Information, these operations are included in Corporate and Other.

Revenues and income (loss) from discontinued operations were as follows:

Major classes of assets and liabilities of discontinued operations held for sale were as follows:

In the fourth quarter of 2002, ConocoPhillips concluded a strategic business review of its company-owned retail sites. The review included quantitative and qualitative measures and identified 3,200 retail sites throughout the United States that did not fit the company’s long-range plans. The assets are being actively marketed by an investment banking firm. The retail sites are being grouped and marketed in packages, including the planned sale of the company’s Circle K Corporation subsidiary. Discussions are under way with potential buyers, and the company expects to complete the sales in 2003.

In connection with the anticipated sale of these retail sites, ConocoPhillips recorded charges totaling $1,412 million before-tax, $1,008 million after-tax, primarily related to the impairment of properties, plants and equipment ($249 million); goodwill ($257 million); intangible asset ($429 million); and provisions for losses and penalties associated with various operating lease commitments ($477 million).

The intangible asset represents the Circle K tradename. Properties, plants and equipment include land, buildings and equipment of owned retail sites and leasehold improvements of leased sites. Fair value determinations were based on estimated sales prices for comparable sites.

The provisions for losses and penalties associated with various operating lease commitments include obligations for residual value guarantee deficiencies, and future minimum rental payments that existed prior to the commitment date that will continue after the exit plan is completed with no economic benefit. It also includes penalties incurred to cancel the contractual arrangements. An additional $130 million of lease loss provisions ($85 million after-tax) will be recognized in 2003 as the company continues to operate the sites until sold.

As a condition to the merger of Conoco and Phillips, the FTC required that the company divest the following assets:

	Phillips’ Woods Cross business unit, which includes the Woods Cross, Utah, refinery and associated motor fuel marketing operations (both retail and wholesale) in Utah, Idaho, Wyoming, and Montana, as well as Phillips’ 50 percent interests in two refined products terminals in Boise and Burley, Idaho;
	Conoco’s Commerce City, Colorado, refinery and related crude oil pipelines;
	Phillips’ Colorado motor fuel marketing operations (both retail and wholesale);
	Phillips’ refined products terminal in Spokane, Washington;
	Phillips’ propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois, which include the propane portions of these terminals and the customer relationships and contracts for the supply of propane therefrom;
	certain of Conoco’s midstream natural gas gathering and processing assets in southeast New Mexico; and
	certain of Conoco’s midstream natural gas gathering assets in West Texas.

Further, the FTC required that certain of these assets be held separately within ConocoPhillips, under the management of a trustee until sold. In connection with these anticipated sales, ConocoPhillips recorded an impairment of $113 million before-tax, $69 million after-tax, related to the Phillips assets in the third quarter of 2002.

In the fourth quarter of 2002, ConocoPhillips agreed to sell its Woods Cross business unit for $25 million, subject to an adjustment for certain pension obligations and the value of crude oil, refined products and other inventories. Also in the fourth quarter, the company sold its propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois. The sales amounts did not differ significantly from the fair-value estimates used in the third quarter impairment calculations. Sale of the Colorado assets and the midstream assets is expected to occur in 2003.

The company’s Netherlands exploration and production assets were sold in the fourth quarter of 2002. No gain or loss was recognized on the sale, as these assets were recorded at fair value in the Conoco purchase price allocation.

Continued