Management’s Discussion and Analysis of Financial
Condition and Results of Operations
March 24, 2003 (Continued)

Outlook
As a condition to the merger, the U.S. Federal Trade Commission (FTC) required that both Conoco and Phillips divest certain assets. In the fourth quarter of 2002, the propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois, were sold and ConocoPhillips agreed to sell its Woods Cross business unit in Salt Lake City, Utah, plus associated assets. See Note 4 — Discontinued Operations in the Notes to Consolidated Financial Statements for a list of the remaining assets held for sale.

In December 2002, ConocoPhillips committed to and initiated a plan to sell a substantial portion of its company-owned retail sites. In connection with the anticipated sale, the company, in the fourth quarter, recorded charges totaling $1,412 million before-tax, $1,008 million after-tax, primarily related to the impairment of properties, plants and equipment; goodwill; intangible assets and provision for losses and penalties to unwind various lease arrangements. The company expects to complete the sale of the sites in 2003.

In December of 2002, political unrest in Venezuela caused economic and other disruptions which shut down most oil production in Venezuela, including the company’s Petrozuata, Hamaca and Gulf of Paria operations. At ConocoPhillips’ Petrozuata joint venture, operations were closed down on December 15, 2002, due to shortages of hydrogen and natural gas (required for processing and fuel). Prior to the disruptions, Petrozuata was producing and processing approximately 120,000 gross (60,000 net) barrels of extra-heavy crude oil per day. Similarly, the disruptions have impacted development production and construction progress at the Hamaca joint-venture project. Construction of the Hamaca upgrader continues, although at a reduced rate. Difficulty in obtaining supplies has been the primary impediment. Production was shut in on December 6, 2002. Prior to the disruptions, Hamaca was producing approximately 55,000 gross (18,000 net) barrels of extra-heavy crude per day. In addition, the crude oil produced by Petrozuata is used as feedstock for ConocoPhillips’ Lake Charles, Louisiana, refinery and a Venezuelan refinery operated by PDVSA. In December 2002, ConocoPhillips substituted about 1.2 million crude barrels for its Lake Charles refinery. At the company’s Sweeny refinery, crude throughputs were reduced slightly due to short supply of Merey Venezuelan crude oil. Overall, there was minimum impact to net income; however, it could reduce net income $30 million to $50 million per month in 2003 as long as production at Petrozuata and Hamaca is shut in. Limited production began from Hamaca and Petrozuata in February 2003.

On March 12, 2002, ConocoPhillips announced that it had signed a Heads of Agreement (LNG HOA) with The Tokyo Electric Power Company, Incorporated (TEPCO) and Tokyo Gas Co., Ltd. (Tokyo Gas) that would enable Phase II, which involves the export and sale of natural gas, of the Bayu-Undan field development to proceed upon resolution of certain legal, regulatory and fiscal issues. The Timor Sea Treaty (Treaty) was ratified by Timor-Leste´ (formerly East Timor) in December 2002 and by Australia in March 2003 and is subject to certain procedural events before it is fully effective. The Treaty will allow the issuance of new production sharing contracts to the existing contractors in the Bayu-Undan unit, which when combined with expected approval of the Development Plan and the expected enactment of certain Timor-Leste´ legislation will provide the legal, regulatory and fiscal basis necessary to proceed with the gas project. Under the terms of the LNG HOA with TEPCO and Tokyo Gas, TEPCO and Tokyo Gas will purchase 3 million tons per year of liquefied natural gas (LNG) for a period of 17 years, utilizing natural gas from the Bayu-Undan field. Shipments would begin in 2006, from an LNG facility near Darwin, Australia, utilizing ConocoPhillips’ Optimized Cascade liquefied natural gas process.

In 2003, ConocoPhillips expects worldwide production of approximately 1.55 million barrels of oil equivalent per day from currently proved reserves. Improvements for the year are expected to come from the United Kingdom, Norway and China. These improvements will be offset by decreases in the U.S. Lower 48 and Canada as a result of the disposition of assets, as well as the impact of the disruptions in Venezuela. In R&M, crude oil throughputs in 2003 are expected to average approximately 2.5 million barrels per day.

Crude oil and natural gas prices are subject to external factors over which the company has no control, such as global economic conditions, political events, demand growth, inventory levels, weather, competing fuels prices and availability of supply. Crude oil prices increased significantly during 2002 due to production restraint by major exporting countries serving to rebalance inventories, supply concerns resulting from Middle East tensions, tropical storms in the U.S. Gulf of Mexico temporarily shutting in oil production and shipping, and the disruptions in Venezuela. Global oil demand is starting to recover on a year-over-year basis, compared with the declines that resulted from the U.S. recession and the events of September 11, 2001. However, the pace of improvement will depend on a continuation of the economic recovery in the United States and globally. Conflicts in oil-producing countries and uncertainties surrounding the global economic recovery could keep prices volatile in 2003. U.S. natural gas prices strengthened considerably at the end of the third quarter and remained strong in the fourth quarter stemming from growing natural gas supply concerns, rising oil prices and an increased demand due to the weather. Supply concerns arose from the decline in domestic gas production and Canadian imports versus 2001, and tropical storms temporarily shutting in production in the Gulf of Mexico.

Refining margins are subject to movements in the price of crude oil and other feedstocks, and the prices of petroleum products, which are subject to market factors over which the company has no control, such as the U.S. and global economies; government regulations; seasonal factors that affect demand, such as the summer driving months; and the levels of refining output and product inventories. Global refining margins remained depressed during much of 2002 due to weak oil demand, relatively high levels of gasoline and distillate inventories and strengthening crude prices, which increased feedstock costs. As a result of tropical storms in the Gulf of Mexico, industry refining crude oil runs were temporarily reduced, which caused product inventory draws in the United States and improved refining margins modestly. Refining and marketing margins can be expected to improve when the U.S. and global economies recover.

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This annual report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements can be identified by the words “expects,” “anticipates,” “intends,” “plans,” “projects,” “believes,” “estimates” and similar expressions.

ConocoPhillips has based the forward-looking statements relating to its operations on its current expectations, estimates and projections about ConocoPhillips and the industries in which it operates in general. ConocoPhillips cautions you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions that the company cannot predict. In addition, ConocoPhillips has based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, ConocoPhillips’ actual outcomes and results may differ materially from what the company has expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:

	fluctuations in crude oil, natural gas and natural gas liquids prices, refining and marketing margins and margins for ConocoPhillips’ chemicals business;
	changes in the business, operations, results and prospects of ConocoPhillips;
	the operation and financing of ConocoPhillips’ midstream and chemicals joint ventures;
	potential failure to realize fully or within the expected time frame the expected cost savings and synergies from the combination of Conoco and Phillips;
	costs or difficulties related to the integration of the businesses of Conoco and Phillips, as well as the continued integration of businesses recently acquired by each of them;
	potential failure or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas reservoir performance;
	unsuccessful exploratory drilling activities;
	failure of new products and services to achieve market acceptance;
	unexpected cost increases or technical difficulties in constructing or modifying facilities for exploration and production projects, manufacturing or refining;
	unexpected difficulties in manufacturing or refining ConocoPhillips’ refined products, including synthetic crude oil, and chemicals products;
	lack of, or disruptions in, adequate and reliable transportation for ConocoPhillips’ crude oil, natural gas and refined products;
	inability to timely obtain or maintain permits, comply with government regulations or make capital expenditures required to maintain compliance;
	potential disruption or interruption of ConocoPhillips’ facilities due to accidents, political events or terrorism;
	international monetary conditions and exchange controls;
	liability for remedial actions, including removal and reclamation obligations, under environmental regulations;
	liability resulting from litigation;
	general domestic and international economic and political conditions, including armed hostilities and governmental disputes over territorial boundaries;
	changes in tax and other laws or regulations applicable to ConocoPhillips’ business; and
	inability to obtain economical financing for exploration and development projects, construction or modification of facilities and general corporate purposes.

Quantitative and Qualitative Disclosures About Market Risk
Financial Instrument Market Risk
ConocoPhillips and certain of its subsidiaries hold and issue derivative contracts and financial instruments that expose cash flows or earnings to changes in commodity prices, foreign exchange rates or interest rates. The company may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of electric power, natural gas, and crude oil and related products, fluctuations in interest rates and foreign currency exchange rates, or to exploit market opportunities.

With the completion of the merger on August 30, 2002, the derivatives policy adopted during the third quarter of 2001 is no longer in effect; however, the ConocoPhillips Board of Directors has approved an “Authority Limitations” document that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations without approval from the Chief Executive Officer. The Authority Limitations document also authorizes the Chief Executive Officer to establish the maximum Value at Risk (VaR) limits for the company. Compliance with these limits is monitored daily. The function of the Risk Management Steering Committee, monitoring the use and effectiveness of derivatives, was assumed by the Chief Financial Officer for risks resulting from foreign currency exchange rates and interest rates, and by the Executive Vice President of Commercial, a new position that reports to the Chief Executive Officer, for commodity price risk. ConocoPhillips’ Commercial Group manages commercial marketing, optimizes the commodity flows and positions of the company, monitors related risks of the company’s upstream and downstream businesses, and selectively takes price risk to add value.

Commodity Price Risk
ConocoPhillips operates in the worldwide crude oil, refined product, natural gas, natural gas liquids, and electric power markets and is exposed to fluctuations in the prices for these commodities. These fluctuations can affect the company’s revenues as well as the cost of operating, investing, and financing activities. Generally, the company’s policy is to remain exposed to market prices of commodities; however, executive management may elect to use derivative instruments to hedge the price risk of the company’s equity crude oil and natural gas production, as well as refinery margins.

The ConocoPhillips’ Commercial Group uses futures, forwards, swaps, and options in various markets to optimize the value of the company’s supply chain, which may move the company’s risk profile away from market average prices to accomplish the following objectives:

	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 the company’s refinery requirements or marketing demand;
	Meet customer needs. Consistent with the company’s policy to generally remain exposed to market prices, the company uses swap contracts to convert fixed-price sales contracts, which are often requested by natural gas and refined product consumers, to a floating market price;
	Manage the risk to the company’s cash flows from price exposures on specific crude oil, natural gas, refined product and electric power transactions; and
	Enable the company to use the market knowledge gained from these activities to do a limited amount of trading not directly related to the company’s physical business. For the 12 months ended December 31, 2002 and 2001, the gains or losses from this activity were not material to the company’s cash flows or income from continuing operations.

ConocoPhillips uses a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2002, as derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those instruments issued or held for trading purposes at December 31, 2002 and 2001, was $0.7 million at each year-end. The VaR for instruments held for purposes other than trading at December 31, 2002 and 2001, was $2 million and $1.7 million, respectively.

Interest Rate Risk
The following tables provide information about the company’s financial instruments that are sensitive to changes in interest rates. The debt tables present principal cash flows and related weighted-average interest rates by expected maturity dates; the derivative table shows the notional quantities on which the cash flows will be calculated by swap termination date. Weighted-average variable rates are based on implied forward rates in the yield curve at the reporting date. The carrying amount of the company’s floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices.

Foreign Currency Risk
ConocoPhillips has foreign currency exchange rate risk resulting from operations in over 40 countries around the world. ConocoPhillips does not comprehensively hedge the exposure to currency rate changes, although the company may choose to selectively hedge exposures to foreign currency rate risk. Examples include firm commitments for capital projects, certain local currency tax payments and dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.

At December 31, 2002, ConocoPhillips had the following significant foreign currency derivative contracts:

	approximately $194 million in foreign currency swaps hedging the company’s European commercial paper program, with a fair value of $7.1 million;
	approximately $536 million in foreign currency swaps hedging short-term intercompany loans between U.K. subsidiaries and a U.S. subsidiary, with a fair value of $9 million; and
	approximately $24 million in foreign currency swaps hedging the company’s firm purchase and sales commitments for gasoline in Germany, with a negative fair value of $4 million.

Although these swaps hedge exposures to fluctuations in exchange rates, the company elected not to utilize hedge accounting as allowed by SFAS No. 133. As a result, the change in the fair value of these foreign currency swaps is recorded directly in earnings. Assuming an adverse hypothetical 10 percent change in the December 31, 2002, exchange rates, the potential foreign currency remeasurement loss in non-cash pretax earning from these swaps, intercompany loans, and commercial paper would be approximately $3 million.

In addition to the intercompany loans discussed above, at December 31, 2002 and 2001, U.S. subsidiaries held long-term sterling-denominated intercompany receivables totaling $152 million and $191 million, respectively, due from a U.K. subsidiary. The U.K. subsidiary also held a dollar-denominated long-term receivable due from a U.S. subsidiary with no balance at December 31, 2002, and a $75 million balance at December 31, 2001. A Norwegian subsidiary held $198 million and $79 million of intercompany U.S. dollar-denominated receivables due from its U.S. parent at December 31, 2002 and 2001, respectively. Also at year-end 2001, a foreign subsidiary with the U.S. dollar as its functional currency owed a $9 million Norwegian kroner-denominated payable to a Norwegian subsidiary. The potential foreign currency remeasurement gains or losses in non-cash pretax earnings from a hypothetical 10 percent change in the year-end 2002 and 2001 exchange rates from these intercompany balances were $35 million and $21 million, respectively.

For additional information about the company’s use of derivative instruments, see Note 16 — Derivative Instruments in the Notes to Consolidated Financial Statements.