Management’s Discussion and Analysis of Financial Condition and Results of Operations

February 26, 2006

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations, and intentions, that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “intends,” “believes,” “expects,” “plans,” “scheduled,” “should,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”

Business Environment and Executive Overview

ConocoPhillips is an international, integrated energy company. We are the third largest integrated energy company in the United States, based on market capitalization. We have approximately 35,600 employees worldwide, and at year-end 2005 had assets of $107 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.” Our business is organized into six operating segments:

Segment Analysis

The E&P segment’s results are most closely linked to crude oil and natural gas prices. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. We benefited from favorable crude oil prices in 2005, which contributed significantly to what we view as strong results from this segment. Industry crude oil prices were approximately $15 per barrel (or 36 percent) higher in 2005, compared with 2004, averaging $56.44 per barrel for West Texas Intermediate. The increase primarily was due to robust global consumption associated with the continuing global economic recovery, as well as oil supply disruptions in Iraq, and disruptions in the U.S. Gulf of Mexico due to hurricanes Katrina and Rita. In addition, there was little excess OPEC production capacity available to replace lost supplies. Industry U.S. natural gas prices were $2.51 per million British thermal units (MMBTU) (or 41 percent) higher in 2005, compared with 2004, averaging approximately $8.64 per MMBTU for Henry Hub. Natural gas prices increased in 2005 due primarily to higher oil prices, continued concerns regarding the adequacy of U.S. natural gas supplies, and the hurricanes disrupting production and distribution in the Gulf Coast region. Looking forward, prices for both crude and natural gas are expected to decrease in 2006 from 2005 levels, while remaining strong relative to long-term historical averages.

     The Midstream segment’s results are most closely linked to natural gas liquids prices. The most important factor on the profitability of this segment is the results from our 50 percent equity investment in DEFS. During 2005, we increased our ownership interest in DEFS from 30.3 percent to 50 percent. During 2005, we recorded a gain of $306 million, after-tax, for our equity share of DEFS’ sale of its general partnership interest in TEPPCO Partners, LP (TEPPCO).

     Refining margins, refinery utilization, cost control, and marketing margins primarily drive the R&M segment’s results. Refining margins are subject to movements in the cost of crude oil and other feedstocks, and the sales prices for refined products, which are subject to market factors over which we have no control. Refining margins in 2005 were stronger in comparison to 2004, resulting in improved R&M profitability. The U.S. Gulf Coast light oil spread increased 68 percent, from an average of $6.49 per barrel in 2004 to $10.92 per barrel in 2005. Key factors driving the 2005 growth in refining margins were healthy growth in demand for refined products in the United States and other countries worldwide, as well as concerns over adequate supplies due to hurricanes Katrina and Rita damaging refining and distribution infrastructure along the Gulf Coast. Our marketing margins were lower in 2005, compared with 2004, due to the market’s inability to pass through higher crude and product costs.

     The LUKOIL Investment segment consists of our investment in the ordinary shares of LUKOIL. In October 2004, we closed on a transaction to acquire 7.6 percent of LUKOIL’s shares held by the Russian government for approximately $2 billion. During the remainder of 2004 and all of 2005, we acquired additional shares in the open market for an additional $2.8 billion, bringing our equity ownership interest in LUKOIL to 16.1 percent by year-end 2005. We initiated this strategic investment to gain further exposure to Russia’s resource potential, where LUKOIL has significant positions in proved reserves and production. We also are benefiting from an increase in proved oil and gas reserves at an attractive cost, and our E&P segment should benefit from direct participation with LUKOIL in large oil projects in the northern Timan-Pechora region of Russia, and an opportunity to potentially participate in the development of the West Qurna field in Iraq.

     The Chemicals segment consists of our 50 percent interest in CPChem. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on market factors over which CPChem has little or no control. CPChem is investing in feedstock-advantaged areas in the Middle East with access to large, growing markets, such as Asia. Our financial results from Chemicals in 2005 were the strongest since the formation of CPChem in 2000, as this business line has emerged from a deep cyclical downturn that began around that time.

     The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. We do not expect the results from this segment to be material to our consolidated results. However, the businesses in this segment allow us to support our primary segments by staying current on new technologies that could become important drivers of profitability in future years.

     At December 31, 2005, we had a debt-to-capital ratio of 19 percent, compared with 26 percent at the end of 2004. The decrease was due to a $2.5 billion reduction in debt during 2005, along with increased equity reflecting strong earnings. Upon completion of the Burlington Resources acquisition, we expect our debt-to-capital ratio to increase into the low-30-percent range. However, we expect debt reduction to be a priority after the acquisition, allowing us to move back toward a mid-to-low-20-percent debt-to-capital ratio within three years.

Results of Operations

Consolidated Results

A summary of the company's net income (loss) by business segment follows:

The improved results in 2005 and 2004 primarily were due to:

In addition, the improved results in 2005 also reflected our equity share of DEFS’ sale of its general partner interest in TEPPCO.

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

Income Statement Analysis

2005 vs. 2004

Sales and other operating revenues increased 33 percent in 2005, while purchased crude oil, natural gas and products increased 39 percent. These increases primarily were due to higher petroleum product prices and higher prices for crude oil, natural gas, and natural gas liquids.

     At its September 2005 meeting, the Emerging Issues Task Force (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, and will impact our reported revenues and purchase costs. 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 if they are entered into “in contemplation” of one another. The new guidance is effective prospectively beginning April 1, 2006, for new arrangements entered into, and for modifications or renewals of existing arrangements. Had this new guidance been effective for the periods included in this report, and depending on the determination of what transactions are affected by the new guidance, we would have been required to reduce sales and other operating revenues in 2005, 2004 and 2003 by $21,814 million, $15,492 million and $11,673 million, respectively, with related decreases in purchased crude oil, natural gas and products. See Note 1 — Accounting Policies, in the Notes to Consolidated Financial Statements, for additional information.

     Equity in earnings of affiliates increased 125 percent in 2005. The increase reflects a full year’s equity earnings from our investment in LUKOIL, as well as improved results from:

Other income increased 52 percent in 2005. The increase was mainly due to higher net gains on asset dispositions in 2005, as well as higher interest income. Asset dispositions in 2005 included the sale of our interest in coalbed methane acreage positions in the Powder River Basin in Wyoming, as well as our interests in Dixie Pipeline, Turcas Petrol A.S., and Venture Coke Company. Asset dispositions in 2004 included our interest in the Petrovera heavy-oil joint venture in Canada.

     Production and operating expenses increased 16 percent in 2005. The E&P segment had higher maintenance and transportation costs; higher costs associated with new fields, including the Magnolia field in the Gulf of Mexico; negative impact from foreign currency exchange rates; and upward insurance premium adjustments. The R&M segment had higher utility costs due to higher natural gas prices, as well as higher maintenance and repair costs due to increased turnaround activity and hurricane impacts.

     Depreciation, depletion and amortization (DD&A) increased 12 percent in 2005, primarily due to new projects in the E&P segment, including a full year’s production from the Magnolia field in the Gulf of Mexico and the Belanak field, offshore Indonesia, as well as new production from the Clair field in the Atlantic Margin and continued ramp-up at the Bayu-Undan field in the Timor Sea.

     We adopted Financial Accounting Standards Board (FASB) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN 47), effective December 31, 2005. As a result, we recognized a charge of $88 million for the cumulative effect of this accounting change. FIN 47 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. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

2004 vs. 2003

Sales and other operating revenues increased 30 percent in 2004, while purchased crude oil, natural gas and products increased 34 percent. These increases mainly were due to:

Equity in earnings of affiliates increased 183 percent in 2004. The increase reflects initial equity earnings from our investment in LUKOIL, as well as improved results from:

Interest and debt expense declined 35 percent in 2004. The decrease primarily was due to lower average debt levels during 2004 and an increased amount of interest being capitalized on major capital projects.

     During 2003, we recognized a $28 million gain on subsidiary equity transactions related to our E&P Bayu-Undan development in the Timor Sea. See Note 5 — Subsidiary Equity Transactions, in the Notes to Consolidated Financial Statements, for additional information.

     We adopted FASB Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143) effective January 1, 2003. As a result, we recognized a benefit of $145 million for the cumulative effect of this accounting change. Also effective January 1, 2003, we adopted FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities,” (FIN 46(R)) for variable interest entities involving synthetic leases and certain other financing structures created prior to February 1, 2003. This resulted in a charge of $240 million for the cumulative effect of this accounting change. We recognized a net $95 million charge in 2003 for the cumulative effect of these two accounting changes.

Segment Results

E&P

  * Excludes our equity share of LUKOIL, which is reported in the LUKOIL Investment segment.
** 2004 and 2003 restated to exclude production, property and similar taxes.

  * Excludes our equity share of LUKOIL reported in the LUKOIL Investment segment.
** Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above.

The E&P segment explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. At December 31, 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.

2005 vs. 2004

Net income from the E&P segment increased 48 percent in 2005. The increase primarily was due to higher sales prices for crude oil, natural gas, natural gas liquids and Syncrude. In addition, increased sales volumes associated with the Magnolia and Bayu-Undan fields, as well as the Hamaca project, contributed positively to net income in 2005. Partially offsetting these items were increased production and operating costs, DD&A and taxes, as well as mark-to-market losses on certain U.K. natural gas contracts.

     If crude oil and natural gas prices in 2006 do not remain at the historically strong levels experienced in 2005, E&P’s earnings would be negatively impacted. See the “Business Environment and Executive Overview” section for additional discussion of crude oil and natural gas prices.

     Proved reserves at year-end 2005 were 7.92 billion barrels of oil equivalent (BOE), compared with 7.61 billion BOE at year-end 2004. This excludes the estimated 1,442 million BOE and 880 million BOE included in the LUKOIL Investment segment at year-end 2005 and 2004, respectively. Also excluded, our Canadian Syncrude mining operations reported 251 million barrels of proved oil sands reserves at year-end 2005, compared with 258 million barrels at year-end 2004.

2004 vs. 2003

Net income from the E&P segment increased 33 percent in 2004, compared with 2003. The increase primarily was due to higher crude oil prices and, to a lesser extent, higher natural gas and natural gas liquids prices. Increased sales prices were partially offset by lower crude oil and natural gas production, as well as higher exploration expenses and lower net gains on asset dispositions. The 2003 period included a net benefit of $142 million for the cumulative effect of accounting changes (SFAS No. 143 and FIN 46(R)), as well as benefits of $233 million from changes in certain international income tax and site restoration laws, and equity realignment of certain Australian operations. Included in 2004 is a $72 million benefit related to the remeasurement of deferred tax liabilities from the 2003 Canadian graduated tax rate reduction and a 2004 Alberta provincial tax rate change.

U.S. E&P

2005 vs. 2004

Net income from our U.S. E&P operations increased 46 percent in 2005. The increase primarily was the result of higher crude oil, natural gas and natural gas liquids prices; higher sales volumes from the Magnolia deepwater field in the Gulf of Mexico, which began producing in late 2004; and higher gains from asset sales in 2005. These items were partially offset by:

U.S. E&P production on a BOE basis averaged 633,000 barrels per day in 2005, compared with 629,000 barrels per day in 2004. The slight increase reflects the positive impact of a full year’s production from the Magnolia field and the purchase of overriding royalty interests in the Utah and San Juan basins, mostly offset by normal field production declines, hurricane-related downtime, and the impact of asset dispositions.

2004 vs. 2003

Net income from our U.S. E&P operations increased 24 percent in 2004, compared with 2003. The increase was mainly the result of higher crude oil prices and, to a lesser extent, higher natural gas and natural gas liquids prices, partially offset by lower crude oil and natural gas production volumes and lower net gains on asset dispositions. In addition, the 2003 period included a net benefit of $142 million for the cumulative effect of accounting changes (SFAS No. 143 and FIN 46(R)).

     U.S. E&P production on a BOE basis averaged 629,000 barrels per day in 2004, down 7 percent from 674,000 BOE per day in 2003. The decreased production primarily was the result of the impact of 2003 asset dispositions, normal field production declines, and planned maintenance activities during 2004.

International E&P

2005 vs. 2004

Net income from our international E&P operations increased 50 percent in 2005. The increase primarily was the result of higher crude oil, natural gas and natural gas liquids prices. In addition, we had higher sales volumes from the Bayu-Undan field in the Timor Sea and the Hamaca project in Venezuela. These items were partially offset by:

International E&P production averaged 910,000 BOE per day in 2005, a slight decrease from 913,000 BOE per day in 2004. Production was favorably impacted in 2005 by the Bayu-Undan field and the Hamaca heavy-oil upgrader project. At the Bayu-Undan field in the Timor Sea, 2005 production was higher than that in 2004, when production was still ramping up. At the Hamaca project in Venezuela, production increased in late 2004 with the startup of a heavy-oil upgrader. These increases in production were offset by the impact of planned and unplanned maintenance, and field production declines. Our Syncrude mining operations produced 19,000 barrels per day in 2005, compared with 21,000 barrels per day in 2004.

2004 vs. 2003
Net income from our international E&P operations increased 43 percent in 2004, compared with 2003. The increase primarily was due to higher crude oil prices and, to a lesser extent, higher natural gas and natural gas liquids prices and higher natural gas liquids volumes. Higher prices were partially offset by increased exploration expenses.

     International E&P’s net income in 2003 also was favorably impacted by the following items:

International E&P production averaged 913,000 BOE per day in 2004, down slightly from 916,000 BOE per day in 2003. Production was favorably impacted in 2004 by the startup of production from the Su Tu Den field in Vietnam in late 2003, the ramp-up of liquids production from the Bayu-Undan field in the Timor Sea since startup in February 2004, and the startup of the Hamaca upgrader in Venezuela in the fourth quarter of 2004. These items were more than offset by the impact of asset dispositions, normal field production declines, and planned maintenance. In addition, our Syncrude mining operations produced 21,000 barrels per day in 2004, compared with 19,000 barrels per day in 2003.

Midstream

* Based on index prices from the Mont Belvieu and Conway market hubs that are weighted
   by natural gas liquids component and location mix.

  * Includes our share of equity affiliates, except LUKOIL, which is included in
     the LUKOIL Investment segment.
** Excludes DEFS

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated — separated into individual components like ethane, butane and propane — and marketed as chemical feedstock, fuel, or blendstock. The Midstream segment consists of our equity investment in Duke Energy Field Services, LLC (DEFS), as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States and Trinidad.

     In July 2005, ConocoPhillips and Duke Energy Corporation (Duke) restructured their respective ownership levels in DEFS, which resulted in DEFS becoming a jointly controlled venture, owned 50 percent by each company. Prior to the restructuring, our ownership interest in DEFS was 30.3 percent. This restructuring increased our ownership in DEFS 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, and a combined payment by ConocoPhillips to Duke and DEFS of approximately $840 million. The Empress plant in Canada was not included in the initial transaction as originally anticipated due to weather-related damage. Subsequently, we sold the Empress plant to Duke in August 2005 for approximately $230 million.

2005 vs. 2004

Net income from the Midstream segment increased 193 percent in 2005. Included in the Midstream segment’s 2005 net income is our share of a gain from DEFS’ sale of its general partnership interest in TEPPCO. Our share of this gain, reflected in equity in earnings of affiliates, was $306 million, after-tax. In addition to this gain, our Midstream segment benefited from improved natural gas liquids prices in 2005, which increased earnings at DEFS, as well as our other Midstream operations. These positive items were partially offset by the loss of earnings from asset dispositions completed in 2004 and 2005.

     Included in the Midstream segment’s net income was a benefit of $17 million in 2005, compared with $36 million in 2004, representing the amortization of the excess amount of our equity interest in the net assets of DEFS over the book value of our investment in DEFS. The reduced amount in 2005 resulted from a significant reduction in the favorable basis difference of our investment in DEFS following the restructuring.

2004 vs. 2003
Net income from the Midstream segment increased 81 percent in 2004, compared with 2003. The improvement was primarily attributable to improved results from DEFS, which had:

Our Midstream operations outside of DEFS had higher earnings in 2004 as well, reflecting the impact of higher natural gas liquids prices that more than offset the effect of asset dispositions in 2004.

     Included in the Midstream segment’s net income was a benefit of $36 million in 2004, the same as 2003, representing the amortization of the excess amount of our 30.3 percent equity interest in the net assets of DEFS over the book value of our investment in DEFS.

R&M

* Excludes excise taxes.

  * Includes our share of equity affiliates, except for our share of LUKOIL, which is
      reported in the LUKOIL Investment segment.
** Weighted-average crude oil capacity for the period. Actual capacity at year-end
      2005 and 2004 was 2,182,000 and 2,160,000 barrels per day, respectively,
      in the United States and 428,000 barrels per day internationally.

The R&M segment’s operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buying, selling and transporting crude oil; and buying, transporting, distributing and marketing petroleum products. R&M has operations in the United States, Europe and Asia Pacific.

2005 vs. 2004

Net income from the R&M segment increased 52 percent in 2005, primarily due to higher worldwide refining margins. See the “Business Environment and Executive Overview” section for our view of the factors that supported the improved refining margins during 2005. Higher refining margins were partially offset by:

If refining margins decline in 2006 from the historically strong levels experienced in 2005, we would expect a corresponding decrease in R&M’s earnings.

2004 vs. 2003

Net income from the R&M segment increased 116 percent in 2004, compared with 2003, primarily due to higher refining margins. This was partially offset by lower U.S. marketing margins, and higher maintenance turnaround and utility costs. The 2003 period included a $125 million net charge for the cumulative effect of an accounting change (FIN 46(R)).

U.S. R&M

2005 vs. 2004

Net income from our U.S. R&M operations increased 57 percent in 2005. The increase mainly was the result of higher U.S. refining margins, partially offset by:

Our U.S. refining capacity utilization rate was 92 percent in 2005, compared with 95 percent in 2004. The 2005 rate was impacted by downtime related to hurricanes. Specifically, the Sweeny, Texas, and Lake Charles, Louisiana, refineries were shutdown in advance of Hurricane Rita. The Sweeny refinery returned to full operation by October. The Lake Charles refinery resumed operations in mid-October, and returned to full operation in November. The Alliance refinery in Belle Chase, Louisiana, was shutdown in advance of Hurricane Katrina, and suffered flooding and damage from that storm. The refinery began partial operation in late-January 2006, and is expected to return to full operation around the end of the first quarter of 2006.

     Effective January 1, 2005, the crude oil capacity at our Sweeny, Texas, refinery was increased by 13,000 barrels per day, as a result of incremental debottlenecking. Effective April 1, 2005, we increased the crude oil processing capacity at our San Francisco, California, refinery by 9,000 barrels per day as a result of a project implementation related to clean fuels.

2004 vs. 2003
Net income from our U.S. R&M operations increased 115 percent in 2004, compared with 2003, primarily due to higher refining margins, partially offset by lower marketing margins, and higher maintenance turnaround and utility costs. The 2003 period included a $125 million net charge for the cumulative effect of an accounting change (FIN 46(R)).
     Our U.S. refining capacity utilization rate was 95 percent in 2004, compared with 96 percent in 2003. The lower capacity utilization was due to increased maintenance downtime.

International R&M

2005 vs. 2004

Net income from our international R&M operations increased 37 percent in 2005, primarily due to higher refining margins, along with improved refinery production volumes and increased results from marketing. These factors were partially offset by negative foreign currency exchange impacts and higher utility costs.

     Our international crude oil capacity utilization rate was 99 percent in 2005, compared with 91 percent in 2004. A larger volume of turnaround activity in 2004 contributed to most of this variance.

     In November 2005, we executed a definitive agreement for the cash purchase of the Wilhelmshaven refinery in Wilhelmshaven, Germany. The purchase would include the 275,000-barrel-per-day refinery, a marine terminal, rail and truck loading facilities and a tank farm, as well as another entity that provides commercial and administrative support to the refinery. The purchase is expected to be completed during the first quarter of 2006, subject to satisfaction of closing conditions, including obtaining the necessary governmental approvals and regulatory permits. The addition of the Wilhelmshaven refinery would increase our overall European refining capacity by approximately 74 percent, from 372,000 barrels per day to 647,000 barrels per day.

2004 vs. 2003

Net income from the international R&M operations increased 119 percent in 2004, compared with 2003, with the improvement primarily attributable to higher refining margins, partially offset by negative foreign currency impacts on operating costs.

LUKOIL Investment

* Represents our net share of our estimate of LUKOIL’s production and processing.

This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. In October 2004, we purchased 7.6 percent of LUKOIL’s ordinary shares held by the Russian government, and during the remainder of 2004, we increased our ownership interest to 10.0 percent. During 2005, we expended $2,160 million to further increase our ownership interest to 16.1 percent. Purchase of LUKOIL shares continued into the first quarter of 2006. The 2005 results for the LUKOIL Investment segment reflect favorable market conditions, including strong crude oil prices.

     In addition to our estimate of our equity share of LUKOIL’s earnings, this segment reflects the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the historical cost of our investment in LUKOIL, and also includes the costs associated with the employees seconded to LUKOIL.

     Because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occurs subsequent to our accounting cycle close, our equity earnings and statistics for our LUKOIL investment include an estimate for the latest quarter presented in a period. This estimate is based on market indicators, historical production trends of LUKOIL, and other factors. Differences between the estimate and actual results are recorded in a subsequent period. This process may create volatility in quarterly trend analysis for this segment, but this volatility will be mitigated when viewing this segment’s results over an annual or longer time frame.

Chemicals

The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for under the equity method. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals such as ethylene, propylene, styrene, benzene, and paraxylene. These products are then marketed and sold, or used as feedstocks to produce plastics and commodity chemicals, such as polyethylene, polystyrene and cyclohexane.

2005 vs. 2004

Net income from the Chemicals segment increased 30 percent in 2005. The increase primarily was attributable to higher margins in the ethylene and polyethylene lines of business. Ethylene margins improved for the second consecutive year and, coupled with the increase in polyethylene margins, indicates that these business lines have improved from a deep cyclical downturn that began in the 1999/2000 time frame. Partially offsetting these margin improvements were higher utility costs, reflecting increased costs of natural gas, as well as hurricane-related impacts on production and maintenance and repair costs.

2004 vs. 2003

Net income from the Chemicals segment increased $242 million in 2004, compared with 2003. The increase reflects that CPChem had improved equity earnings from Qatar Chemical Company Ltd. (Q-Chem), an olefins and polyolefins complex in Qatar, and Saudi Chevron Phillips Company, an aromatics complex in Saudi Arabia. Results from CPChem’s consolidated operations also improved due to higher ethylene and benzene margins, as well as increased ethylene, polyethylene and normal alpha olefins sales volumes.

Emerging Business

The Emerging Businesses segment includes the development of new businesses outside our traditional operations. These activities include gas-to-liquids (GTL) operations, power generation, technology solutions such as sulfur removal technologies, and emerging technologies, such as renewable fuels and emission management technologies.

2005 vs. 2004

The Emerging Businesses segment incurred a net loss of $21 million in 2005, compared with a net loss of $102 million in 2004. The improved results in 2005 reflect:

2004 vs. 2003

Emerging Businesses incurred a net loss of $102 million in 2004, compared with a net loss of $99 million in 2003. Contributing to the higher losses in 2004 were lower domestic power margins and higher maintenance costs, as well as increased costs associated with the Immingham power plant project in the United Kingdom, which entered the initial commissioning phase during 2004. Prior to the initial commissioning phase, most costs associated with this project were construction activities and thus capitalized. This project completed the initial commissioning phase and began commercial operations in October 2004. Partially offsetting these items were lower research and development costs, compared with 2003, which included the costs of a demonstration GTL plant then under construction. Construction of the GTL plant was substantially completed during the second quarter of 2003.

Corporate and Other

* Includes a $107 million charge related to discontinued operations, primarily
   related to the adoption of FIN 46(R).

2005 vs. 2004

After-tax net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 18 percent in 2005, primarily due to lower average debt levels and increased interest income. Interest income increased as a result of our higher average cash balances during 2005. These items were partially offset by increased early debt retirement fees and a lower amount of interest being capitalized in 2005, reflecting the completion of several major projects in the second half of 2004.

     After-tax corporate general and administrative expenses decreased 14 percent in 2005. The decrease reflects increased allocations of management-level stock-based compensation to the operating segments, which had previously been retained at corporate. These increased corporate allocations did not have a material impact on the operating segments’ results. This was partially offset by increased charitable contributions, reflecting disaster relief following the southeast Asia tsunami and Gulf of Mexico hurricanes.

     Discontinued operations net income declined in 2005, reflecting asset dispositions completed during 2004 and 2005.

     The category “Other” consists primarily of items not directly associated with the operating segments on a stand-alone basis, including certain foreign currency transaction gains and losses, and environmental costs associated with sites no longer in operation. Results from Other were lower in 2005, mainly due to unfavorable foreign currency transaction impacts.

2004 vs. 2003

Net interest decreased 19 percent in 2004, primarily due to lower average debt levels, an increased amount of interest being capitalized in 2004, lower charges for premiums paid on the early retirement of debt, and lower costs associated with the receivables monetization program.

     After-tax corporate general and administrative expenses increased 23 percent in 2004. The increase reflects higher compensation costs, which includes increased stock-based compensation due to an increase in both the number of units issued and higher stock prices in the 2004 period.

     Discontinued operations net income declined 91 percent in 2004, reflecting asset dispositions completed during 2003 and 2004.

     Results from Other were lower in 2004, mainly due to the inclusion in the 2003 period of gains related to insurance demutualization benefits, negative foreign currency transaction impacts, higher environmental costs and increased minority interest expense.

Capital Resources and Liquidity

Financial Indicators

* Capital includes total debt, minority interests and common stockholder's equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, primarily cash generated from operating activities. In addition, during 2005 we raised $768 million in funds from the sale of assets. During 2005, available cash was used to support our ongoing capital expenditures and investments program, repay debt, pay dividends and purchase shares of our common stock. Total dividends paid on our common stock in 2005 were $1.6 billion. During 2005, cash and cash equivalents increased $827 million to $2.2 billion.

     In addition to cash flows from operating activities and proceeds from asset sales, we also rely on our commercial paper and credit facility programs, as well as our $5 billion universal shelf registration statement, to support our short- and long-term liquidity requirements. We anticipate that these sources of liquidity will be adequate to meet our funding requirements through 2007, including our capital spending program and required debt payments. We anticipate that the cash portion of the pending acquisition of Burlington Resources Inc., approximately $17.5 billion, will be financed with a combination of short- and long-term debt and available cash. For additional information about the acquisition, see Note 28 — Pending Acquisition of Burlington Resources Inc., in the Notes to Consolidated Financial Statements.

     Our cash flows from operating activities increased in each of the annual periods from 2003 through 2005. Favorable market conditions played a significant role in the upward trend of our cash flows from operating activities. Excluding the Burlington Resources acquisition and absent any unusual event during 2006, we expect that market conditions will again be the most important factor affecting our 2006 operating cash flows, when compared with 2005.

Significant Sources of Capital

Operating Activities

During 2005, cash of $17,628 million was provided by operating activities, compared with cash from operations of $11,959 million in 2004. This 47 percent increase was primarily due to higher income from continuing operations and a positive impact from working capital changes, partly offset by a greater amount of undistributed equity earnings.

During 2004, cash flow from operations increased $2,603 million to $11,959 million. Contributing to the improvement, compared with 2003, was an increase in income from continuing operations primarily resulting from higher crude oil, natural gas and natural gas liquids prices, as well as improved worldwide refining margins. This benefit was partly offset by a higher retained interest in receivables sold to a Qualifying Special Purpose Entity (QSPE). For additional information on receivables sold to a QSPE, see Receivables Monetization in the Off-Balance Sheet Arrangements section.

     Our cash flows from operating activities for both the short- and long-term are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During 2004 and 2005, we benefited from historically high crude oil and natural gas prices, as well as strong refining margins. The sustainability of these prices and margins is driven by market conditions over which we have no control. In addition, the level of our production volumes of crude oil, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, the addition of proved reserves through exploratory success, and the timely and cost-effective development of those proved reserves.

     We will need to continue to add to our proved reserve base through exploration and development of new fields, or by acquisition, and to apply new technologies and processes to boost recovery from existing fields in order to maintain or increase production and proved reserves. We have been successful in the past in maintaining or adding to our production and proved reserve base and, although it cannot be assured, anticipate being able to do so in the future. Including the impact of our equity investments and after adjusting our 2003 production for assets sold in 2003 and early 2004, our BOE production has increased in each of the past three years. Going forward, based on our 2005 production level of 1.79 million BOE per day, we expect our annual production growth to average in the range of 2 percent to 4 percent over the five-year period ending in 2010. These projections are tied to projects currently scheduled to begin production or ramp-up in those years, exclude our Canadian Syncrude mining operations, and do not include any impact from our pending acquisition of Burlington Resources Inc.

     Including the impact of our equity investments, our reserve replacement over the three-year period ending December 31, 2005, exceeded 100 percent. Contributing to our success during this three-year period were proved reserves added through our investment in LUKOIL, other purchases of reserves in place, and extensions and discoveries. Although it cannot be assured, going forward, we expect to more than replace our production over the next three-year period, 2006 through 2008. This expectation is based on our current slate of exploratory and improved recovery projects. It does not include any impact from our pending acquisition of Burlington Resources Inc. As discussed in Critical Accounting Policies, engineering estimates of proved reserves are imprecise, and therefore, each year reserves may be revised upward or downward due to the impact of changes in oil and gas prices or as more technical data becomes available on the reservoirs. In 2005 and 2003, revisions increased our reserves, while in 2004, revisions decreased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.

     The net addition of proved undeveloped reserves accounted for 44 percent, 38 percent and 76 percent of our total net additions in 2005, 2004 and 2003, respectively. During these years, we converted, on average, 16 percent per year of our proved undeveloped reserves to proved developed reserves. Of the proved undeveloped reserves we had at December 31, 2005, we estimated that the average annual conversion rate for these reserves for the following three years will be approximately 15 percent. For additional information related to the development of proved undeveloped reserves, see the discussion under the E&P section of Capital Spending. The anticipated production and reserve replacement results are subject to risks, including reservoir performance; operational downtime; finding and development execution; obtaining management, Board and third-party approval of development projects in a timely manner; regulatory changes; geographical location; market prices; and environmental issues; and therefore, cannot be assured.

Asset Sales

Proceeds from asset sales in 2005 were $768 million. Following the merger of Conoco and Phillips in August 2002, we initiated an asset disposition program. Our ultimate target was to raise approximately $4.5 billion by the end of 2004. During 2004, proceeds from asset sales were $1.6 billion, bringing total proceeds at the end of 2004 to approximately $5.0 billion since the program began. Proceeds from these asset sales were used primarily to pay off debt.

Commercial Paper and Credit Facilities

During 2005, we replaced our $2.5 billion four-year revolving credit facility that would have expired in October 2008 and our $2.5 billion five-year facility that would have expired in October 2009 with two new revolving credit facilities totaling $5 billion. Both new facilities expire in October 2010. The new facilities are available for use as direct bank borrowings or as support for the ConocoPhillips $5 billion commercial paper program, the ConocoPhillips Qatar Funding Ltd. commercial paper program, and could be used to support issuances of letters of credit totaling up to $750 million. The facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreements do 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. There were no outstanding borrowings under these facilities at December 31, 2005.

     While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our operating cash flows remain exposed to the volatility of commodity crude oil and natural gas prices and refining and marketing margins, as well as periodic cash needs to finance tax payments and crude oil, natural gas and petroleum product purchases. Our primary funding source for short-term working capital needs is the ConocoPhillips $5 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally limited to 90 days. At December 31, 2005, we had no commercial paper outstanding under this program, compared with $544 million of commercial paper outstanding at December 31, 2004. In December 2005, ConocoPhillips Qatar Funding Ltd. initiated a $1.5 billion commercial paper program to be used to fund commitments relating to the Qatargas 3 project. At December 31, 2005, commercial paper outstanding under this program was $32 million.

     Since we had $32 million of commercial paper outstanding and had issued $62 million of letters of credit, we had access to $4.9 billion in borrowing capacity under the two revolving credit facilities as of December 31, 2005. In addition, our $2.2 billion cash balance also supported our liquidity position.

     At December 31, 2005, Moody’s Investor Service had a rating of A1 on our senior long-term debt; and Standard and Poors’ Rating Service and Fitch had ratings of A-. We do not have any ratings triggers on any of our corporate debt that would cause an automatic event of default in the event of a downgrade of our credit rating and thereby impact our access to liquidity. In the event that our credit rating deteriorated to a level that would prohibit us from accessing the commercial paper market, we would still be able to access funds under our $5 billion revolving credit facilities.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission, under which we have available to issue and sell a total of $5 billion of various types of debt and equity securities.

Minority Interests

At December 31, 2005, we had outstanding $1,209 million of equity in less than wholly owned consolidated subsidiaries held by minority interest owners, including a minority interest of $507 million in Ashford Energy Capital S.A. The remaining minority interest amounts are primarily related to controlled-operating joint ventures with minority interest owners. The largest of these, $682 million, was related to the Bayu-Undan liquefied natural gas project in the Timor Sea and northern Australia.

     In December 2001, in order to raise funds for general corporate purposes, Conoco and Cold Spring Finance S.a.r.l. (Cold Spring) formed Ashford Energy Capital S.A. through the contribution of a $1 billion Conoco subsidiary promissory note and $500 million cash by Cold Spring. Through its initial $500 million investment, Cold Spring is entitled to a cumulative annual preferred return based on three-month LIBOR rates, plus 1.32 percent. The preferred return at December 31, 2005, was 5.37 percent. In 2008, and at each 10-year anniversary thereafter, Cold Spring may elect to remarket their investment in Ashford, and if unsuccessful, could require ConocoPhillips to provide a letter of credit in support of Cold Spring’s investment, or in the event that such letter of credit is not provided, then cause the redemption of their investment in Ashford. Should ConocoPhillips’ credit rating fall below investment grade on a redemption date, Ashford would require a letter of credit to support $475 million of the term loans, as of December 31, 2005, made by Ashford to other ConocoPhillips subsidiaries. If the letter of credit is not obtained within 60 days, Cold Spring could cause Ashford to sell the ConocoPhillips subsidiary notes. At December 31, 2005, Ashford held $1.8 billion of ConocoPhillips subsidiary notes and $28 million in investments unrelated to ConocoPhillips. We report Cold Spring’s investment as a minority interest because it is not mandatorily redeemable and the entity does not have a specified liquidation date. Other than the obligation to make payment on the subsidiary notes described above, Cold Spring does not have recourse to our general credit.

Off-Balance Sheet Arrangements

Receivables Monetization

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. The revolving-period securitization arrangement was terminated on August 31, 2005, and at this time, we have no plans to renew the arrangement. See Note 13 — Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.

Preferred Securities

In 1997, we formed a statutory business trust, Phillips 66 Capital II (Trust II), with ConocoPhillips owning all of the common securities of the trust. The sole purpose of the trust was to issue preferred securities to outside investors, investing the proceeds thereof in an equivalent amount of subordinated debt securities of ConocoPhillips. The trust was established to raise funds for general corporate purposes.

     At December 31, 2005 and 2004, Trust II had $350 million of mandatorily redeemable preferred securities outstanding, whose sole asset was $361 million of ConocoPhillips’ subordinated debt securities, which bear interest at 8 percent. Distributions on the trust preferred securities are paid by the trust with funds from interest payments made by ConocoPhillips on the subordinated debt securities. We made interest payments of $29 million in both 2005 and 2004. In addition, we guaranteed the payment obligations of the trust on the trust preferred securities to the extent we made interest payments on the subordinated debt securities. When we redeem the subordinated debt securities, Trust II is required to apply all redemption proceeds to the immediate redemption of the preferred securities. See Note 3 — Changes in Accounting Principles and Note 17 — Preferred Stock and Other Minority Interests, in the Notes to Consolidated Financial Statements, for additional information.

Affiliated Companies

As part of our normal ongoing business operations and consistent with normal industry practice, we invest in, and enter into, numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At December 31, 2005, we were liable for certain contingent obligations under various contractual arrangements as described below.

For additional information about guarantees see Note 14 — Guarantees, in the Notes to Consolidated Financial Statements.

Capital Requirements

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

     Our balance sheet debt at December 31, 2005, was $12.5 billion. This reflects debt reductions of approximately $2.5 billion during 2005. The decline in debt primarily resulted from a reduction of $512 million in our commercial paper balance; the redemption in November of our $750 million 6.35% Notes due 2009, at a premium of $42 million plus accrued interest; the redemption in late March of our $400 million 3.625% Notes due 2007, at par plus accrued interest; and the purchase, at market prices, and retirement of $752 million of various ConocoPhillips bond issues. In conjunction with the redemption of the 6.35% Notes and the 3.625% Notes, $750 million and $400 million, respectively, of interest rate swaps were cancelled. The note redemptions, interest rate swap cancellations, and bond issue purchases resulted in after-tax losses of $92 million.

     On February 4, August 11, and November 15, 2005, we announced separate stock repurchase programs, each of which provides for the purchase of up to $1 billion of the company’s common stock over a period of up to two years. Acquisitions for the share repurchase programs are made at management’s discretion at prevailing prices, subject to market conditions and other factors. Purchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock purchased under the programs are held as treasury shares. During 2005, we purchased 32.1 million shares of our common stock, at a cost of $1.9 billion under the programs.

     We entered into a credit agreement with Qatargas 3, whereby we will provide loan financing of approximately $1.2 billion for the construction of the facilities. This financing will represent 30 percent of the project’s total debt financing. Through December 31, 2005, we had provided $36 million in loan financing. See the “Off-Balance Sheet Arrangements” section for additional information on Qatargas 3.

     In July 2004, we announced the finalization of our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in a proposed LNG receiving terminal in Quintana, Texas. Construction began in early 2005. We do not have an ownership interest in the facility, but we do have a 50 percent interest in the general partnership managing the venture, along with contractual rights to regasification capacity of the terminal. We entered into a credit agreement with Freeport LNG, whereby we will provide loan financing of approximately $630 million for the construction of the facility. Through December 31, 2005, we had provided $212 million in loan financing, including accrued interest.

     In the fall of 2004, ConocoPhillips and LUKOIL agreed to the expansion of the Varandey terminal as part of our investment in the OOO Naryanmarneftegaz (NMNG) joint venture. 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 intends to complete an expansion of the terminal oil-throughput capacity from 30,000 barrels per day to up to 240,000 barrels per day in late 2007, with ConocoPhillips participating in the design and financing of the terminal expansion. We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion, but we will have no governance or ownership interest in the terminal. Based on preliminary budget estimates from the operator, we expect our total loan obligation for the terminal expansion to be approximately $330 million. This amount will be adjusted as the design is finalized and the expansion project proceeds. Through December 31, 2005, we had provided $61 million in loan financing.

     We account for our loans to Qatargas 3, Freeport LNG and Varandey Terminal Company as financial assets in the “Investments and long-term receivables” line on the balance sheet.

     In February 2006, we announced a quarterly dividend of 36 cents per share, representing a 16 percent increase over the previous quarter’s dividend of 31 cents per share. The dividend is payable March 1, 2006, to stockholders of record at the close of business February 21, 2006.

Contractual Obligations

The following table summarizes our aggregate contractual fixed and
variable obligations as of December 31, 2005:

   *  Total debt excluding capital lease obligations. Includes net unamortized
       premiums and discounts.
**   Represents any agreement to purchase goods or services that is enforceable
       and legally binding and that specifies all significant terms. The majority of
       the purchase obligations are market-based contracts. Includes: (1) our
       commercial activities of $50,744 million, of which $18,276 million are
       primarily related to the supply of crude oil to our refineries and the
       optimization of the supply chain, $10,649 million primarily related to
       natural gas for resale to customers, $9,664 million primarily related to
       the supply of unfractionated NGLs to fractionators, optimization of NGL
       assets, and for resale to customers, $3,327 million related to transportation,
       $3,763 million related to product purchase, $2,142 million of futures,
       $2,114 million related to power trades and $809 million related to the
       purchase side of exchange agreements; (2) $30,126 million of purchase
       commitments for products, mostly natural gas and natural gas liquids, from
       CPChem over the remaining term of 95 years; and (3) purchase commitments
       for jointly owned fields and facilities where we are the operator, of which
       some of the obligations will be reimbursed by our co-owners in these
       properties. Does not include: (1) purchase commitments for jointly owned
       fields and facilities where we are not the operator; (2) our agreement to
       purchase up to 104,000 barrels per day of Petrozuata crude oil for a
       market-based formula price over the term of the Petrozuata joint venture
       (about 35 years) in the event that Petrozuata is unable to sell the production
       for higher prices; and (3) an agreement to purchase up to 165,000 barrels
       per day of Venezuelan Merey, or equivalent, crude oil for a market price
       over a remaining 14-year term if a variety of conditions are met.
*** Does not include: (1) Taxes — the company’s consolidated balance
       sheet reflects liabilities related to income, excise, property, production,
       payroll and environmental taxes. We anticipate the current liability of
       $3,516 million for accrued income and other taxes will be paid in the next
       year. We have other accrued tax liabilities whose resolution may not
       occur for several years, so it is not possible to determine the exact timing
       or amount of future payments. Deferred income taxes reflect the net tax
       effect of temporary differences between the carrying amounts of assets
       and liabilities for financial reporting purposes and the amounts used for
       tax purposes; (2) Pensions — for the 2006 through 2010 time period,
       we expect to contribute an average of $365 million per year to our qualified
       and non-qualified pension and postretirement medical plans in the
       United States and an average of $130 million per year to our non-U.S. plans,
       which are expected to be in excess of required minimums in many cases.
       The U.S. five-year average consists of $420 million for the next three years
       and then approximately $275 million per year as our pension plans become
       better funded. Our required minimum funding in 2006 is expected to be
       $65 million in the United States and $95 million outside the United States;
       and (3) Interest — we anticipate payments of $793 million in 2006,
       $1,387 million for the period 2007 through 2008, $1,288 million for the
       period 2009 through 2010, and $7,164 million for the remaining years to
       total $10,632 million.

Capital Spending

Capital Expenditures and Investments

    * Does not include any amounts for the pending acqusition of
       Burlington Resources Inc.
  ** Discretionary expenditures in 2006 for potential additional equity investment
       in LUKOIL to increase our ownership percentage up to 20 percent,
       from 16.1 percent at December 31, 2005, are not included in our
       2006 budget amounts.
*** Excludes discontinued operations.

Our capital spending for continuing operations for the three-year period ending December 31, 2005, totaled $27.3 billion, including a combined $4.8 billion in 2004 through 2005 relating to our purchase of a 16.1 percent interest in LUKOIL. During the three-year period, spending was primarily focused on the growth of our E&P segment, with 60 percent of total spending for continuing operations in this segment.

     Excluding discretionary expenditures for potential additional investment in LUKOIL, our capital budget for 2006 is $11.2 billion. Included in this amount are $447 million in capitalized interest and $44 million that is expected to be funded by minority interests in the Bayu-Undan gas export project. We plan to direct approximately 67 percent of our 2006 capital budget to E&P and 31 percent to R&M.

E&P

Capital spending for continuing operations for E&P during the three-year period ending December 31, 2005, totaled $16.4 billion. The expenditures over the three-year period supported several key exploration and development projects including:

Capital expenditures for construction of our Endeavour Class tankers, as well as for an upgrade to the Trans-Alaska Pipeline System pump stations and purchase of an additional interest in the pipeline, were also included in the E&P segment.

United States

Alaska

During the three-year period ending December 31, 2005, we made capital expenditures for the construction of double-hulled Endeavour Class tankers for use in transporting Alaskan crude oil to the U.S. West Coast and Hawaii. We expect the fifth and final Endeavour Class tanker to be in Alaska North Slope service in 2006, although contractual and hurricane-related issues may further delay delivery of this vessel.

     We continued development drilling in the Greater Kuparuk Area, the Greater Prudhoe Area, the Alpine field, including Alpine’s first satellite fields — Nanuq and Fiord, and the West Sak development. In addition, we completed both Phase I and Phase II of the Alpine Capacity Expansion project. We also participated in exploratory drilling on the North Slope and acquired additional acreage during this three-year period.

     During 2004, we and our co-venturers in the Trans-Alaska Pipeline System began a project to upgrade the pipeline’s pump stations that is expected to be fully complete in 2006.

Lower 48 States

In the Lower 48, we continued to explore or develop our acreage positions in the deepwater Gulf of Mexico, South Texas, the San Juan Basin, the Permian Basin, and the Texas Panhandle. In the Gulf of Mexico, we began production in late 2004 from the Magnolia field, where development drilling continued in 2005. We also began production from the K2 field in Green Canyon Block 562 in May 2005.

     Onshore capital was focused on natural gas developments in the San Juan Basin of New Mexico and the Lobo Trend of South Texas, and the acquisition in 2005 of limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our natural gas production.

Canada
In Canada, we continued with development of the Syncrude Stage III expansion-mining project in the Canadian province of Alberta, where an upgrader expansion project is expected to be fully operational in mid-2006.

     We also continued with development of the Surmont heavy-oil project. During 2005, funds were also invested to acquire an additional 6.5 percent interest in Surmont, increasing our interest to 50 percent. Over the life of this 30+ year project, we anticipate that approximately 500 production and steam-injection well pairs will be drilled. In 2005, our capital expenditures associated with the development of the Surmont project, excluding the acquisition of the additional interest, were approximately $93 million.

     In addition, capital expenditures were also focused on the development of our conventional crude oil and natural gas reserves in western Canada.

South America

At our Hamaca project in Venezuela, construction of an upgrader to convert heavy crude oil into a medium-grade crude oil became fully operational in the fourth quarter of 2004.

     In the Gulf of Paria, funds were invested to construct a floating storage offtake facility and to construct and install a wellhead platform in the Corocoro field. The Corocoro drilling program is expected to begin in the second quarter of 2006.

Northwest Europe
In the U.K. and Norwegian sectors of the North Sea, funds were invested during the three-year period ending December 31, 2005, for development of the Ekofisk Area growth project, where production began in the fourth quarter of 2005; the U.K. Clair field, where production began in early 2005; the Saturn project, where production began in the third quarter of 2005; the CMS3 area, comprising five natural gas fields in the southern sector of the U.K. North Sea, where the final field began production in 2004; the Britannia satellite fields, Callanish and Brodgar, where production is expected in 2007; and the Alvheim development project, where production is scheduled to begin in 2007.

Africa
In Nigeria, we made capital expenditures for the ongoing development of onshore oil and natural gas fields, and for ongoing exploration activities both onshore and on deepwater leases. Funding was also provided for our share of the basic phase of the Brass liquefied natural gas (LNG) project for the front-end engineering and design and related activities to move the project to a final investment decision.

Russia and Caspian Sea

Russia

In June 2005, we invested funds of $512 million to acquire a 30 percent economic interest and a 50 percent voting interest in NMNG, a joint venture with LUKOIL to explore for and develop oil and gas resources in the northern part of Russia’s Timan-Pechora province. The June acquisition price was based on preliminary estimates of capital expenditures and working capital. The purchase price is expected to be finalized in the first quarter of 2006.

Caspian Sea
Construction activities began in 2004 to develop the Kashagan field on the Kazakhstan shelf in the North Caspian Sea. Additional exploratory drilling through 2004 has resulted in the discovery of a total of five fields in the area. In March 2005, agreement was reached with the Republic of Kazakhstan government to conclude the sale of BG International’s interest in the North Caspian Sea Production Sharing Agreement to several of the remaining partners and for the subsequent sale of one-half of the acquired interests to KazMunayGas. This agreement increased our ownership interest from 8.33 percent to 9.26 percent.

Asia Pacific

Timor Sea

In the Timor Sea, we continued with development activities associated with Phase I of the Bayu-Undan project, where condensate and natural gas liquids are separated and removed, and the dry gas re-injected into the reservoir. Production of liquids began from Phase I in February of 2004, and development drilling concluded at the end of March 2005.

     In June 2003, we received approval from the Timor Sea Designated Authority for Phase II, the development of an LNG plant near Darwin, Australia, as well as a gas pipeline from Bayu-Undan to the LNG facility. Construction activities continued through 2005, and the first LNG cargo from the facility was loaded in February 2006.

Indonesia
In Indonesia, funds were used for the completion of the Belanak field in the South Natuna Sea Block B, including the construction of the Belanak floating production, storage and offloading (FPSO) facility and associated gas plant facilities on the FPSO. Oil production began from Belanak in late 2004 and first condensate production and gas exports began in June and October 2005, respectively. Also, in Block B we began development of the Kerisi and Hiu fields. In South Sumatra, following the execution of the West Java gas sales agreement in August 2004, we began the development of the Suban Phase II project, which is an expansion of the existing Suban gas plant. Also in South Sumatra, we completed the construction of the South Jambi shallow gas project in the South Jambi B Block, where first production began in June 2004.

China

Following approval from the Chinese government in early 2005, we began development of Phase II of the Peng Lai 19-3 oil field, as well as concurrent development of the nearby 25-6 field. The development of Peng Lai 19-3 and Peng Lai 25-6 will include multiple wellhead platforms and a larger FPSO facility.

Vietnam

In Vietnam’s Block 15-1, funds were invested for the Su Tu Den Phase I southwest area development project, where production began in the fourth quarter of 2003 and where water injection facilities were put into service in 2004. Also in Block 15-1, preliminary engineering for the nearby Su Tu Vang development began in early 2005, and approval for the development was obtained in late 2005.

     On Block 15-2, we upgraded facilities at our producing Rang Dong field in 2003 and continued further development of the field, including the central part of the field, where two additional platforms and additional production and injection wells were completed in the third quarter of 2005.

2006 Capital Budget

E&P’s 2006 capital budget is $7.5 billion, 12 percent higher than actual expenditures in 2005. Twenty-four percent of E&P’s 2006 capital budget is planned for the United States, with 48 percent of that slated for Alaska.

     We plan to spend $861 million in 2006 for our Alaskan operations. A majority of the capital spending will fund Prudhoe Bay, Greater Kuparuk and Western North Slope operations — including two Alpine satellites and West Sak field developments, construction to complete our fifth and final Endeavour Class tanker, and exploration activities.

     In the Lower 48, offshore capital expenditures will be focused on continued development of the Ursa field and the completion of the K2 and Magnolia developments in deepwater Gulf of Mexico. Onshore capital will focus primarily on developing natural gas reserves within core areas, including the San Juan Basin of New Mexico and the Lobo Trend of South Texas.

     E&P is directing $5.7 billion of its 2006 capital budget to international projects, including payments for the acquisition of an interest in our former oil and gas production operations in Libya. The agreement for our return was signed and approved by the Libyan government in late-December 2005. In addition, funds in 2006 also will be directed to developing major long-term projects, including the Bayu-Undan gas development project in the Timor Sea; the Kashagan project in the Caspian Sea and the NMNG joint venture in northern Russia; the Britannia satellites, Ekofisk Area growth and Alvheim projects in the North Sea; the Bohai Bay project in China; the Syncrude expansion, Surmont heavy-oil and the Mackenzie Delta gas projects in Canada; the Belanak, Kerisi-Hiu and Suban Phase II projects in Indonesia; the Corocoro project in Venezuela; and the Qatargas 3 LNG project in Qatar.

     In late-December 2005, we announced that, in conjunction with our co-venturers, we reached agreement with the Libyan National Oil Corporation on the terms under which we would return to our former oil and natural gas production operations in the Waha concessions in Libya. ConocoPhillips and Marathon each hold a 16.33 percent interest, Amerada Hess holds an 8.16 percent interest, and the Libyan National Oil Corporation holds the remaining 59.16 percent interest. The fiscal terms of the agreement are similar to the terms in effect at the time of the suspension of the co-venturers’ activities in 1986. The terms include a 25-year extension of the concessions to 2031-2034; a payment to the Libyan National Oil Corporation of $1.3 billion ($520 million net to ConocoPhillips) for the acquisition of an ownership interest in, and extension of, the concessions; and a contribution to unamortized investments made since 1986 of $530 million ($212 million net to ConocoPhillips) that were agreed to be paid as part of the 1986 standstill agreement to hold the assets in escrow for the U.S.-based co-venturers. Of the total amount to be paid by ConocoPhillips, $520 million was paid in January 2006, and the remaining $212 million is expected to be paid in December 2006.

Proved Undeveloped Reserves

Costs incurred for the years ended December 31, 2005, 2004, and 2003, relating to the development of proved undeveloped oil and gas reserves were $3.4 billion, $2.4 billion, and $2.0 billion, respectively. During these years, we converted, on average, 16 percent per year of our proved undeveloped reserves to proved developed reserves. Although it cannot be assured, estimated future development costs relating to the development of proved undeveloped reserves for the years 2006 through 2008 are projected to be $2.9 billion, $2.2 billion, and $1.3 billion, respectively. Of our 2,515 million BOE proved undeveloped reserves at year-end 2005, we estimated that the average annual conversion rate for these reserves for the three-year period ending 2008 will be approximately 15 percent.

     Approximately 80 percent of our proved undeveloped reserves at year-end 2005 were associated with nine major developments and our investment in LUKOIL. Seven of the major developments are currently producing and are expected to have proved reserves convert from undeveloped to developed over time as development activities continue and/or production facilities are expanded or upgraded, and include:

The remaining two major projects, Qatargas 3 in Qatar and the Kashagan field in Kazakhstan, will have undeveloped proved reserves convert to developed as these projects begin production.

Midstream

Capital spending for continuing operations for Midstream during the three-year period ending December 31, 2005, was primarily related to increasing our ownership interest in DEFS in 2005 from 30.3 percent to 50 percent.

R&M

Capital spending for continuing operations for R&M during the three-year period ending December 31, 2005, was primarily for clean fuels projects to meet new environmental standards, refinery-upgrade projects to improve product yields, and the operating integrity of key processing units, as well as for safety projects. During this three-year period, R&M capital spending for continuing operations was $4.3 billion, representing 16 percent of our total capital spending for continuing operations.

     Key projects during the three-year period included:

The integration of the crude unit and coker purchased adjacent to our Wood River refinery enables the refinery to process additional heavier, lower-cost crude oil.
     The new diesel hydrotreater at the Rodeo facility of our San Francisco refinery became operational at the end of March 2005. The new diesel hydrotreater provides the capability to produce reformulated California highway diesel over one year ahead of the June 2006 deadline.

     Internationally, we continued to invest in our ongoing refining and marketing operations to upgrade and increase the profitability of our existing assets, including a replacement reformer at our Humber refinery in the United Kingdom. In November 2005, we announced the planned acquisition of the 275,000-barrel-per-day Wilhelmshaven refinery in Germany. The purchase is expected to be finalized in the first quarter of 2006.

2006 Capital Budget

R&M’s 2006 capital budget is $3.5 billion, a 101 percent increase over actual spending in 2005. Domestic spending is expected to consume 52 percent of the R&M budget.

     We plan to direct about $1.5 billion of the R&M capital budget to domestic refining, of which approximately $400 million is earmarked for clean fuels projects already in progress and about $700 million is for sustaining projects related to reliability, safety and the environment. In addition, about $400 million is intended for strategic and other investments to increase crude oil capacity, expand conversion capability, improve energy efficiency and increase clean product yield. Our U.S. marketing and transportation businesses are expected to spend about $275 million.

     Internationally, we plan to spend approximately $1.7 billion on our R&M operations. Of this amount, about $1.4 billion is intended for the acquisition of the Wilhelmshaven refinery in Germany, including the initial expenditures for a deep conversion project and other improvements at the refinery. The remaining international R&M capital budget is for projects to strengthen our existing assets within Europe and Asia.

Emerging Businesses

Capital spending for Emerging Businesses during the three-year period ending December 31, 2005, was primarily for construction of the Immingham combined heat and power cogeneration plant near the company’s Humber refinery in the United Kingdom. The plant began commercial operations in October 2004.

Contingencies

Legal and Tax Matters

We accrue for contingencies when a loss is probable and the amounts can be reasonably estimated. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on the company’s financial statements.

Environmental

We are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production industry; and refining, marketing and transportation of crude oil and refined products businesses. The most significant of these environmental laws and regulations include, among others, the:

These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
     Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

     The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.

     For example, the EPA has promulgated rules regarding the sulfur content in highway diesel fuel, which become applicable in June 2006. In April 2003, the EPA proposed a rule regarding emissions from non-road diesel engines and limiting non-road diesel fuel sulfur content. The non-road rule, as promulgated in June 2004, significantly reduces non-road diesel fuel sulfur content limits as early as 2007. We are evaluating and developing capital strategies for future integrated compliance of our diesel fuel for the highway and non-road markets.

     Additional areas of potential air-related impact are the proposed revisions to the National Ambient Air Quality Standards (NAAQS) and the Kyoto Protocol. In July 1997, the EPA promulgated more stringent revisions to the NAAQS for ozone and particulate matter. Since that time, final adoption of these revisions has been the subject of litigation (American Trucking Association, Inc. et al. v. United States Environmental Protection Agency) that eventually reached the U.S. Supreme Court during the fall of 2000. In February 2001, the U.S. Supreme Court remanded this matter, in part, to the EPA to address the implementation provisions relating to the revised ozone NAAQS. The EPA responded by promulgating a revised implementation rule for its new eight-hour NAAQS on April 30, 2004. Several environmental groups have since filed challenges to this new rule. Depending upon the outcomes of the various challenges, area designations, and the resulting State Implementation Plans, the revised NAAQS could result in substantial future environmental expenditures for us. In recent action, the EPA has proposed an even more stringent particulate-matter standard and continues to consider increased stringency for ozone requirements as well. Outcomes of the deliberations remain indeterminate.

     In 1997, an international conference on global warming concluded an agreement, known as the Kyoto Protocol, which called for reductions of certain emissions that contribute to increases in atmospheric greenhouse gas concentrations. The United States has not ratified the treaty codifying the Kyoto Protocol but may in the future ratify, support or sponsor either it or other climate change related emissions reduction programs. Other countries where we have interests, or may have interests in the future, have made commitments to the Kyoto Protocol and are in various stages of formulating applicable regulations. Because considerable uncertainty exists with respect to the regulations that would ultimately govern implementation of the Kyoto Protocol, it currently is not possible to accurately estimate our future compliance costs under the Kyoto Protocol, but they could be substantial. The Kyoto Protocol became effective as to its ratifying countries in February 2005.

     We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require that contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater. MTBE standards continue to evolve, and future environmental expenditures associated with the remediation of MTBE-contaminated underground storage tank sites could be substantial.

     At RCRA permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.

     We, from time to time, receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2004, we reported we had been notified of potential liability under CERCLA and comparable state laws at 64 sites around the United States. At December 31, 2005, we had resolved five of these sites, reclassified one site, and had received six new notices of potential liability, leaving 66 unresolved sites where we have been notified of potential liability.

     For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

     Expensed environmental costs were $847 million in 2005 and are expected to be about $790 million in 2006 and $850 million in 2007. Capitalized environmental costs were $1,235 million in 2005 and are expected to be about $1,000 million and $630 million in 2006 and 2007, respectively.

Remediation Accruals

We accrue for remediation activities when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

     Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of December 31, 2005.

     Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

     At December 31, 2005, our balance sheet included total accrued environmental costs related to continuing operations of $989 million, compared with $1,061 million at December 31, 2004. We expect to incur a substantial majority of these expenditures within the next 30 years.

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

Other

We have deferred tax assets related to certain accrued liabilities, loss carryforwards, and credit carryforwards. Valuation allowances have been established for certain foreign operating and domestic capital loss carryforwards that reduce deferred tax assets to an amount that will, more likely than not, be realized. Uncertainties that may affect the realization of these assets include tax law changes and the future level of product prices and costs. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income.

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 December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123(R)), which supercedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” that we adopted at the beginning of 2003. SFAS 123(R) prescribes the accounting for a wide range of share-based compensation arrangements, including 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 adopted the provisions of this Statement on January 1, 2006, using the modified-prospective transition method, and do not expect the provisions of this new pronouncement to have a material impact on our financial statements. For more information on our adoption of SFAS No. 123 and its effect on net income, see Note 1 — Accounting Policies, in the Notes to Consolidated Financial Statements.

     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 do not expect this Statement to have a significant impact on our financial statements.

     At the 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 1 — Accounting Policies, in the Notes to Consolidated Financial Statements.

Critical Accounting Policies

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1 — Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting policies are discussed with the Audit and Finance Committee at least annually. We believe the following discussions of critical accounting policies, along with the discussions of contingencies and of deferred tax asset valuation allowances in this report, address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Oil and Gas Accounting

Accounting for oil and gas exploratory activity is subject to special accounting rules that are unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.

Property Acquisition Costs

For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.

     This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. By the end of the contractual period of the leasehold, the impairment probability percentage will have been adjusted to 100 percent if the leasehold is expected to be abandoned, or will have been adjusted to zero percent if there is an oil or gas discovery that is under development. See the supplemental Oil and Gas Operations disclosures about Costs Incurred and Capitalized Costs for more information about the amounts and geographic locations of costs incurred in acquisition activity and the amounts on the balance sheet related to unproved properties. At year-end 2005, the book value of the pools of property acquisition costs, that individually are relatively small and thus subject to the above-described periodic leasehold impairment calculation, was approximately $512 million and the accumulated impairment reserve was approximately $167 million. The weighted average judgmental percentage probability of ultimate failure was approximately 72 percent and the weighted average amortization period was approximately 2.9 years. If that judgmental percentage were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2006 would increase by $6 million. The remaining $2,688 million of capitalized unproved property costs at year-end 2005 consisted of individually significant leaseholds, mineral rights held into perpetuity by title ownership, exploratory wells currently drilling, and suspended exploratory wells. Management periodically assesses individually significant leaseholds for impairment based on exploration and drilling efforts to date on the individual prospects. Of this amount, approximately $1.7 billion is concentrated in nine major projects. Except for Surmont, which is scheduled to begin production in late 2006, management expects less than $100 million to move to proved properties in 2006. Most of the remaining value is associated with Mackenzie Delta, Alaska North Slope and Australia natural gas projects, on which we continue to work with partners and regulatory agencies in order to develop. See the following discussion of Exploratory Costs for more information on suspended exploratory wells.

Exploratory Costs

For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well.

     If a judgment is made that the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the mere chance that future market conditions will improve or new technologies will be found that would make the project’s development economically profitable. In these situations, recoverable reserves are considered economic if the quantity found justifies completion of the find as a producing well, without considering the major infrastructure capital expenditures that will need to be made. Once all additional exploratory drilling and testing work has been completed, the economic viability of the overall project, including any major infrastructure capital expenditures that will need to be made, is evaluated. If economically viable, internal company approvals are obtained to move the project into the development phase. Often, the ability to move the project into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as the company is actively pursuing such approvals and permits and believes they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase and the oil and gas reserves are designated as proved reserves. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field, or we seek government or co-venturer approval of development plans or seek environmental permitting.

     Unlike leasehold acquisition costs, there is no periodic impairment assessment of suspended exploratory well costs. In addition to reviewing suspended well balances quarterly, management continuously monitors the results of the additional appraisal drilling and seismic work and expenses the suspended well costs as a dry hole when it judges that the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.
     At year-end 2005, total suspended well costs were $339 million, compared with $347 million at year-end 2004. For additional information on suspended wells, see Note 8 — Properties, Plants and Equipment, in the Notes to Consolidated Financial Statements.

Proved Oil and Gas Reserves and Canadian Syncrude Reserves

Engineering estimates of the quantities of recoverable oil and gas reserves in oil and gas fields and in-place crude bitumen volumes in oil sand mining operations are inherently imprecise and represent only approximate amounts because of the subjective judgments involved in developing such information. Reserve estimates are based on subjective judgments involving geological and engineering assessments of in-place hydrocarbon volumes, the production or mining plan, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s exploration and production (E&P) operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineering department has policies and procedures in place that are consistent with these authoritative guidelines. We have qualified and experienced internal engineering personnel who make these estimates for our E&P segment. Proved reserve estimates are updated annually and take into account recent production and seismic information about each field or oil sand mining operation. Also, as required by authoritative guidelines, the estimated future date when a field or oil sand mining operation will be permanently shut down for economic reasons is based on an extrapolation of sales prices and operating costs prevalent at the balance sheet date. This estimated date when production will end affects the amount of estimated recoverable reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Year-end 2005 estimated reserves related to our LUKOIL Investment segment were based on LUKOIL’s year-end 2004 oil and gas reserves. Because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occurs subsequent to our accounting cycle close, our 16.1 percent equity share of LUKOIL’s oil and gas proved reserves at year-end 2005 were estimated based on LUKOIL’s prior year’s report (adjusted for known additions, license extensions, dispositions, and public information) and included adjustments to conform to our reserve policy and provided for estimated 2005 production. Any differences between the estimate and actual reserve computations will be recorded in a subsequent period. This estimate-to-actual adjustment will then be a recurring component of future period reserves.

     The judgmental estimation of proved reserves also is important to the income statement because the proved oil and gas reserve estimate for a field or the estimated in-place crude bitumen volume for an oil sand mining operation serves as the denominator in the unit-of-production calculation of depreciation, depletion and amortization of the capitalized costs for that asset. At year-end 2005, the net book value of productive E&P properties, plants and equipment subject to a unit-of-production calculation, including our Canadian Syncrude bitumen oil sand assets, was approximately $31.9 billion and the depreciation, depletion and amortization recorded on these assets in 2005 was approximately $2.5 billion. The estimated proved developed oil and gas reserves on these fields were 4.8 billion BOE at the beginning of 2005 and were 5.2 billion BOE at the end of 2005. The estimated proved reserves on the Canadian Syncrude assets were 258 million barrels at the beginning of 2005 and were 251 million barrels at the end of 2005. If the judgmental estimates of proved reserves used in the unit-of-production calculations had been lower by 5 percent across all calculations, pretax depreciation, depletion and amortization in 2005 would have been increased by an estimated $131 million. Impairments of producing oil and gas properties in 2005, 2004 and 2003 totaled $4 million, $67million and $225 million, respectively. Of these write-downs, only $1 million in 2005, $52 million in 2004 and $19 million in 2003 were due to downward revisions of proved reserves. The remainder of the impairments in 2003 resulted either from properties being designated as held for sale or from the repeal in 2003 of the Norway Removal Grant Act (1986) that increased asset removal obligations.

Impairment of Assets

Long-lived assets 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. Individual assets are grouped for impairment purposes based on a judgmental assessment of 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. Because there usually is a lack of quoted market prices for long-lived assets, the fair value usually is based on the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The expected future cash flows used for impairment reviews and related fair-value calculations are based on judgmental assessments of future production volumes, prices and costs, considering all available information at the date of review. See Note 10 — Property Impairments, in the Notes to Consolidated Financial Statements, for additional information.

Asset Retirement Obligations and Environmental Costs

Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve removal and disposal of offshore oil and gas platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos abatement at refineries. The estimated discounted costs of dismantling and removing these facilities are accrued at the installation of the asset. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs are changing constantly, as well as political, environmental, safety and public relations considerations.

     In addition, under the above or similar contracts, permits and regulations, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations, and remediation activities required by the state of Alaska at exploration and production sites. Future environmental remediation costs are difficult to estimate because they 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.
     See Note 1 — Accounting Policies, Note 3 — Changes in Accounting Principles, Note 11 — Asset Retirement Obligations and Accrued Environmental Costs, and Note 15 — Contingencies and Commitments, in the Notes to Consolidated Financial Statements, for additional information.

Business Acquisitions

Purchase Price Allocation

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business. For most assets and liabilities, purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. The most difficult estimations of individual fair values are those involving properties, plants and equipment and identifiable intangible assets. We use all available information to make these fair value determinations and, for major business acquisitions, typically engage an outside appraisal firm to assist in the fair value determination of the acquired long-lived assets. We have, if necessary, up to one year after the acquisition closing date to finish these fair value determinations and finalize the purchase price allocation.

Intangible Assets and Goodwill

In connection with the acquisition of Tosco Corporation on September 14, 2001, and the merger of Conoco and Phillips on August 30, 2002, we recorded material intangible assets for trademarks and trade names, air emission permit credits, and permits to operate refineries. These intangible assets were determined to have indefinite useful lives and so are not amortized. This judgmental assessment of an indefinite useful life has to be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines that these intangible assets then have definite useful lives, amortization will have to commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to periodic lower-of-cost-or-market tests that require management’s judgment of the estimated fair value of these intangible assets. See Note 9 — Goodwill and Intangibles, in the Notes to Consolidated Financial Statements, for additional information.

     Also, in connection with the acquisition of Tosco, the merger of Conoco and Phillips, and the acquisition of an ownership interest in a producing oil business in Libya, we recorded a material amount of goodwill. Under the accounting rules for goodwill, this intangible asset is not amortized. Instead, goodwill is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of any reporting units within the company that have recorded goodwill with the recorded net book value (including the goodwill) of the reporting unit. If the estimated fair value of the reporting unit is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required that year. If, however, the estimated fair value of the reporting unit is below the recorded net book value, then a second step must be performed to determine the amount of the goodwill impairment to record, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical new acquisition of the reporting unit. The various purchase business combination rules are followed to determine a hypothetical purchase price allocation for the reporting unit’s assets and liabilities. The residual amount of goodwill that results from this hypothetical purchase price allocation is compared with the recorded amount of goodwill for the reporting unit, and the recorded amount is written down to the hypothetical amount if lower. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment. A component is a reporting unit if the component constitutes a business for which discrete financial information is available and segment management regularly reviews the operating results of that component. However, two or more components of an operating segment shall be aggregated and deemed a single reporting unit if the components have similar economic characteristics. Within our E&P segment and our R&M segment, we determined that we have one and two reporting units, respectively, for purposes of assigning goodwill and testing for impairment. These are Worldwide Exploration and Production, Worldwide Refining and Worldwide Marketing. Our Midstream, Chemicals and Emerging Businesses operating segments were not assigned any goodwill from the merger because the two predecessor companies’ operations did not overlap in these operating segments so we were unable to capture significant synergies and strategic advantages from the merger in these areas.

     In our E&P segment, management reporting is primarily organized based on geographic areas. All of these geographic areas have similar business processes, distribution networks and customers, and are supported by a worldwide exploration team and shared services organizations. Therefore, all components have been aggregated into one reporting unit, Worldwide Exploration and Production, which is the same as the operating segment. In contrast, in our R&M segment, management reporting is primarily organized based on functional areas. Because the two broad functional areas of R&M have dissimilar business processes and customers, we concluded that it would not be appropriate to aggregate these components into only one reporting unit at the R&M segment level. Instead, we identified two reporting units within the operating segment: Worldwide Refining and Worldwide Marketing. Components in those two reporting units have similar business processes, distribution networks and customers. If we later reorganize our businesses or management structure so that the components within these three reporting units are no longer economically similar, the reporting units would be revised and goodwill would be re-assigned using a relative fair value approach in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” Goodwill impairment testing at a lower reporting unit level could result in the recognition of impairment that would not otherwise be recognized at the current higher level of aggregation. In addition, the sale or disposition of a portion of these three reporting units will be allocated a portion of the reporting unit’s goodwill, based on relative fair values, which will adjust the amount of gain or loss on the sale or disposition.

     Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units for purposes of performing the first step of the periodic goodwill impairment test. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and observed market multiples of operating cash flows and net income, and may engage an outside appraisal firm for assistance. In addition, if the first test step is not met, further judgment must be applied in determining the fair values of individual assets and liabilities for purposes of the hypothetical purchase price allocation. Again, management must use all available information to make these fair value determinations and may engage an outside appraisal firm for assistance. At year-end 2005, the estimated fair values of our Worldwide Exploration and Production, Worldwide Refining, and Worldwide Marketing reporting units ranged from between 17 percent to 67 percent higher than recorded net book values (including goodwill) of the reporting units. However, a lower fair value estimate in the future for any of these reporting units could result in impairment of the $15.3 billion of goodwill.

     During 2006, we expect to acquire Burlington Resources Inc., subject to approval of the transaction by Burlington’s shareholders and appropriate regulatory agencies. We expect this acquisition to result in the accounting recognition of a material amount of additional goodwill, all of which will be associated with our Worldwide Exploration and Production reporting unit. Based on our goodwill impairment testing at year-end 2005, we anticipate that this reporting unit will have adequate capacity to absorb this additional goodwill from the Burlington transaction and will not result in an impairment.

Use of Equity Method Accounting for Investment in LUKOIL

In October 2004, we purchased 7.6 percent of the outstanding ordinary shares of LUKOIL from the Russian government. During the remainder of 2004 and throughout 2005, we purchased additional shares of LUKOIL on the open market and reached an ownership level of 16.1 percent in LUKOIL by the end of 2005. On January 24, 2005, LUKOIL held an extraordinary general meeting of stockholders at which our nominee to the LUKOIL Board of Directors was elected under the cumulative voting rules in Russia, and certain amendments to LUKOIL’s charter were approved which provide protections to preserve the significant influence of major stockholders in LUKOIL, such as ConocoPhillips. In addition, during the first quarter of 2005, the two companies began the secondment of managerial personnel between the two companies.

     Based on the overall facts and circumstances surrounding our investment in LUKOIL, we concluded that we have significant influence over the operating and financial policies of LUKOIL and thus applied the equity method of accounting beginning in the fourth quarter of 2004. Determination of whether one company has significant influence over another, the criterion required by APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock,” in order to use equity method accounting, is a judgmental accounting decision based on the overall facts and circumstances of each situation. Under the equity method of accounting, we estimate and record our weighted-average ownership share of LUKOIL’s net income (determined in accordance with accounting principles generally accepted in the United States (U.S. GAAP)) each period as equity earnings on our income statement, with a corresponding increase in our recorded investment in LUKOIL. Cash dividends received from LUKOIL will reduce our recorded investment in LUKOIL. The use of equity-method accounting also requires us to supplementally report our ownership share of LUKOIL’s oil and gas disclosures in our report.

     If future facts and circumstances were to change to where we no longer believe we have significant influence over LUKOIL’s operating and financial policies, we would have to change our accounting classification for the investment to an available-for-sale equity security under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” If that unlikely event were to occur, our investment in LUKOIL would be marked to market each period, based on LUKOIL’s publicly traded share price, with the offset recorded as a component of other comprehensive income. Additionally, we would no longer record our ownership share of LUKOIL’s net income each period and any cash dividends would be reported as dividend income when declared by LUKOIL. We also would no longer be able to supplementally report our ownership share of LUKOIL’s oil and gas disclosures.

     During 2005, we recorded $756 million of equity-method earnings from our 13.1 percent weighted-average ownership level in LUKOIL. Our reported earnings for the LUKOIL Investment segment of $714 million included the above equity-method earnings, less certain expenses and taxes. At December 31, 2005, we supplementally reported an estimated 1,242 million barrels of crude oil and 1,197 billion cubic feet of natural gas proved reserves from our ownership level of 16.1 percent at year-end 2005. Because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occurs subsequent to our accounting cycle close, we have used all available information to estimate LUKOIL’s U.S. GAAP net income for the year 2005 for purposes of our equity-method accounting. Any differences between our estimate of fourth-quarter 2005 net income and the actual LUKOIL U.S. GAAP net income will be recorded in our 2006 equity earnings. In addition, we used all available information to estimate our share of LUKOIL’s oil and gas disclosures. If, instead of equity-method accounting, we had been required to follow the requirements of SFAS No. 115 for our investment in LUKOIL, the mark-to-market adjustment to reflect LUKOIL’s publicly-traded share price at year-end 2005 would have been a pretax benefit to other comprehensive income of approximately $3,298 million. Also, $19 million of acquisition-related costs would have been expensed and $756 million of current year equity-method earnings would not have been recorded.

     At the end of 2005, the cost of our investment in LUKOIL exceeded our 16.1 percent share of LUKOIL’s historical U.S. GAAP balance sheet equity by an estimated $1,375 million. Under the accounting guidelines of APB Opinion No. 18, we account for the basis difference between the cost of our investment and the amount of underlying equity in the historical net assets of LUKOIL as if LUKOIL were a consolidated subsidiary. In other words, a hypothetical purchase price allocation is performed to determine how LUKOIL assets and liabilities would have been adjusted in a hypothetical push-down accounting exercise to reflect the actual cost of our investment in LUKOIL’s shares. Once these hypothetical push-down adjustments have been identified, the nature of the hypothetically adjusted assets or liabilities determines the future amortization pattern for the basis difference. The majority of the basis difference is associated with LUKOIL’s developed property, plant and equipment base. The earnings we recorded for our LUKOIL investment thus included a reduction for the amortization of this basis difference. In 2005, we completed the purchase price allocation related to our 2004 share purchases of LUKOIL.

Projected Benefit Obligations

Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. This also impacts the required company contributions into the plans. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations. For Employee Retirement Income Security Act-qualified pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination of the judgmental assumptions used in determining required company contributions into plan assets. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate would increase annual benefit expense by $105 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by $40 million. In determining the discount rate, we use yields on high-quality fixed income investments (including among other things, Moody’s Aa corporate bond yields) with adjustments as needed to match the estimated benefit cash flows of our plans.

Outlook

On the evening of December 12, 2005, ConocoPhillips and Burlington Resources Inc. announced that they had signed a definitive agreement under which ConocoPhillips would acquire Burlington Resources Inc. The transaction has a preliminary value of $33.9 billion. This transaction is expected to close on March 31, 2006, subject to approval from Burlington Resources shareholders at a special meeting set for March 30, 2006.

     Under the terms of the agreement, Burlington Resources shareholders will receive $46.50 in cash and 0.7214 shares of ConocoPhillips common stock for each Burlington Resources share they own. This represents a transaction value of $92 per share, based on the closing of ConocoPhillips shares on Friday, December 9, 2005, the last unaffected day of trading prior to the announcement. We anticipate that the cash portion of the purchase price, approximately $17.5 billion, will be financed with a combination of short- and long-term debt and available cash.

     Burlington Resources is an independent exploration and production company that holds a substantial position in North American natural gas reserves and production.

     Upon completion of the transaction, Bobby S. Shakouls, Burlington Resources’ President and Chief Executive Officer, and William E. Wade Jr., currently an independent director of Burlington Resources, will join our Board of Directors. For additional information about the acquisition, see Note 28 — Pending Acquisition of Burlington Resources Inc., in the Notes to Consolidated Financial Statements.

     In October 2005, we announced that we had reached an agreement in principle with the state of Alaska on the base fiscal contract terms for an Alaskan natural gas pipeline project. In early 2006, the state of Alaska announced that they had reached an agreement in principle with all the co-venturers in the project. Once the final form of agreement is reached among all the parties, it will be subject to approval by the Alaska State Legislature before it can be executed. Additional agreements for the gas to transit Canada will also be required.

     In February 2006, the governor of Alaska announced proposed legislation to change the state’s oil and gas production tax structure. The proposed structure would be based on a percentage of revenues less certain expenditures, and include certain incentives to encourage new investment. If approved by the legislature, the new tax structure would go into effect July 1, 2006. If enacted, we would anticipate an increase in our production taxes in Alaska, based on an initial assessment of the proposed legislation.

     In addition to our participation in the LNG regasification terminal at Freeport, Texas, we are pursuing three other proposed LNG regasification terminals in the United States. The Beacon Port Terminal would be located in federal waters in the Gulf of Mexico, 56 miles south of the Louisiana mainland. Also in the Gulf of Mexico is the proposed Compass Port Terminal, to be located approximately 11 miles offshore Alabama. The third proposed facility would be a joint venture located in the Port of Long Beach, California. Each of these proposed projects is in various stages of the regulatory permitting process.

     In the United Kingdom, with effect from January 1, 2006, legislation is pending to increase the rate of supplementary corporation tax applicable to U.K. upstream activity from 10 percent to 20 percent. This would result in the overall U.K. upstream corporation tax rate increasing from 40 percent to 50 percent. The earnings impact of these changes will be reflected in our financial statements when the legislation is substantially enacted, which could occur in the third quarter of 2006. Upon enactment, we expect to record a charge for the revaluing of the December 31, 2005, deferred tax liability, as well as an adjustment to our tax expense to reflect the new rate from January 1, 2006, through the date of enactment. We are currently evaluating the full financial impact of this proposed legislation on our financial statements.

     In February 2003, the Venezuelan government implemented a currency exchange control regime. The government has published legal instruments supporting the controls, one of which establishes official exchange rates for the U.S. dollar. The devaluation of the Venezuelan currency by approximately 11 percent in March 2005 did not have a significant impact on our operations there; however, future changes in the exchange rate could have a significant impact. Based on public comments by Venezuelan government officials, Venezuelan legislation could be enacted that would increase the income tax rate on foreign companies operating in the Orinoco Oil Belt from 34 percent to 50 percent. We continue to work closely with the Venezuelan government on any potential impacts to our heavy-oil projects in Venezuela.

     In November 2005, the Mackenzie Gas Project (MGP) proponents elected to proceed to the regulatory hearings, which began in January 2006. This followed an earlier halting of selected data collection, engineering and preliminary contracting work due to insufficient progress on key areas critical to the project. Since that time, considerable progress has been made with respect to Canadian government socio-economic funding, regulatory process and schedule, the negotiation of benefits and access agreements with four of the five aboriginal groups in the field areas and on the pipeline route. First production from the Parsons Lake field is now expected in 2011.

     In December 2003, we signed a Statement of Intent with Qatar Petroleum regarding the construction of a gas-to-liquids (GTL) plant in Ras Laffan, Qatar. Preliminary engineering and design studies have been completed. In April 2005, the Qatar Minister of Petroleum stated that there would be a postponement of new GTL projects in order to further study impacts on infrastructure, shipping and contractors, and to ensure that the development of its gas resources occurs at a sustainable rate. Work continues with Qatar authorities on the appropriate timing of the project to meet the objectives of Qatar and ConocoPhillips.

     In R&M, the optimization of spending related to clean fuels project initiatives will be an important focus area during 2006. We expect our average refinery crude oil utilization rate for 2006 to average in the mid-nineties. This projection excludes the impact of our equity investment in LUKOIL and the pending acquisition of the Wilhelmshaven refinery in Germany.

     Also in R&M, we are planning to spend $4 billion to $5 billion over the period 2006 through 2011 to increase our U.S. refining system’s ability to process heavy-sour crude oil and other lower-quality feedstocks. These investments are expected to incrementally increase refining capacity and clean products yield at our existing facilities, while providing competitive returns.

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

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “will,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.

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

Quantitative and Qualitative Disclosures

About Market Risk

Financial Instrument Market Risk

We and certain of our 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. We may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of electric power, natural gas, crude oil and related products, fluctuations in interest rates and foreign currency exchange rates, or to exploit market opportunities.

     Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board 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, and compliance with these limits is monitored daily. The Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates, while the Executive Vice President of Commercial monitors commodity price risk. Both report to the Chief Executive Officer. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, monitors related risks of our upstream and downstream businesses, and selectively takes price risk to add value.

Commodity Price Risk

We operate in the worldwide crude oil, refined products, natural gas, natural gas liquids, and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing, and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, executive management may elect to use derivative instruments to hedge the price risk of our crude oil and natural gas production, as well as refinery margins.

     Our Commercial organization uses futures, forwards, swaps, and options in various markets to optimize the value of our supply chain, which may move our risk profile away from market average prices to accomplish the following objectives:

We use 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, 2005, 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, 2005 and 2004, was immaterial to our net income and cash flows. The VaR for instruments held for purposes other than trading at December 31, 2005 and 2004, was also immaterial to our net income and cash flows.

Interest Rate Risk

The following tables provide information about our 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 our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices.

During the fourth quarter of 2003, we executed certain interest rate swaps that had the effect of converting $1.5 billion of debt from fixed to floating rate, but during 2005 we terminated the majority of these interest rate swaps as we redeemed the associated debt. This reduced the amount of debt being converted from fixed to floating by the end of 2005 to $350 million. Under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” these swaps were designated as hedging the exposure to changes in the fair value of $400 million of 3.625% Notes due 2007, $750 million of 6.35% Notes due 2009, and $350 million of 4.75% Notes due 2012. These swaps qualify for the shortcut method of hedge accounting, so over the term of the swaps we will not recognize gain or loss due to ineffectiveness in the hedge.

Foreign Currency Risk

We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency rate changes, although we 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, 2005 and 2004, we held foreign currency swaps hedging short-term intercompany loans between European subsidiaries and a U.S. subsidiary. Although these swaps hedge exposures to fluctuations in exchange rates, we 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. Since the gain or loss on the swaps is offset by the gain or loss from remeasuring the intercompany loans into the functional currency of the lender or borrower, there would be no material impact to income from an adverse hypothetical 10 percent change in the December 31, 2005 or 2004, exchange rates. The notional and fair market values of these positions at December 31, 2005 and 2004, were as follows:

For additional information about our use of derivative instruments, see Note 16 — Financial Instruments and Derivative Contracts, in the Notes to Consolidated Financial Statements.