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| 2003 Annual Report | 
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Management’s
Discussion and Analysis of Financial 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, intentions, and resources 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,” “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.” Results
of Operations Business
Environment and Executive Summary Crude oil and natural gas prices, along with refining margins, play the most significant roles in our profitability. These prices and margins are driven by market factors over which we have no control. However, from a competitive perspective, there are other important factors that we must manage well to be successful, including:
Many of our key performance indicators are shown in the statistical tables provided at the beginning of our operating segment sections that follow. These include crude oil and natural gas prices and production, natural gas liquids prices, refining capacity utilization, and refinery output. We also use the “return on capital employed” measure. Other significant factors that can and/or do affect our profitability include:
Segment
Analysis 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 30.3 percent equity investment in Duke Energy Field Services, LLC (DEFS). Higher natural gas liquids prices improved results from this segment in 2003. In early 2004, we approved the disposal of some of our non-DEFS Midstream assets located in the lower 48 states that are not associated with our E&P operations. 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 2003 were much improved over 2002, resulting in improved R&M profitability. See the “Outlook” section for further discussion of refining margins in 2003 and our view of their potential movement into 2004. At year-end 2003, we estimated that a 25 cent per barrel change in refining margins would have an estimated $125 million annual impact on net income. For wholesale marketing margins, the corresponding impact is approximately $100 million for a 1 cent per gallon margin change. Our refineries operated at 94 percent of rated capacity in 2003, and our goal in 2004 is to operate at about the same level. The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (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. The chemicals and plastics industry has been in a cyclical downturn for the last several years. In this difficult market environment, CPChem has placed great emphasis on safety, cost control and managing its capacity utilization. In addition, CPChem is investing in feedstock-advantaged areas in the Middle East with access to large, growing markets, such as Asia. With its low cost structure, we feel CPChem is well positioned to benefit from improved margins when the chemicals industry emerges from its downturn. 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, 2003, we had a debt-to-capital ratio of 34 percent. We have made a priority of using funds available after paying dividends and capital spending to reduce debt. We reduced our debt by $4.8 billion in 2003. We feel that by lowering our debt-to-capital ratio over the next several years to about 30 percent, we can improve our cost of capital and further position ourselves for growth opportunities in the future. Consolidated
Results A
summary of the company's net income (loss) by business segment follows: 2003
vs. 2002
See the “Segment Results” section for additional information on our E&P and R&M results, as well as our other reporting segments. 2002
vs. 2001 Income
Statement Analysis
In addition to the merger impact, sales and other operating revenues and purchase costs increased because of higher prices for key products such as crude oil, natural gas, automotive gasoline and distillates. These are commodity products and their price levels are determined by market factors. Our share of earnings from affiliates acquired in the merger accounted for the majority of the increase in the equity earnings. Of these, the E&P joint ventures in Canada (Petrovera) and Venezuela (Petrozuata), along with CFJ Properties in our R&M segment, provided the largest equity earnings. On February 18, 2004, we sold our interest in the Petrovera joint venture. Of the equity affiliates held prior to the merger, our equity earnings from DEFS improved on higher natural gas liquids prices, and our earnings from Hamaca, an E&P heavy-oil joint venture in Venezuela, increased due to higher crude oil production. A higher net gain on asset sales was primarily responsible for the increase in other income in 2003. During 2003 we sold several E&P operations that did not fit into our long-term growth strategy. In addition, 2003 included gains attributable to insurance demutualization benefits. See the Corporate and Other section of “Segment Results” for additional information on these insurance benefits. Selling, general and administrative expenses in 2002 included a $246 million charge for the write-off of in-process research and development costs acquired in the merger. The absence of such a significant charge in the 2003 period reduced the impact of the merger on this line item. Property impairments increased by $75 million in 2003, compared with 2002. The 2003 impairments were recorded as a result of asset status changes from held-for-use to held-for-sale, producing properties that failed to meet recoverability tests, and tax law changes in Norway affecting asset removal costs. During 2002, property impairments were triggered by asset dispositions and the impairment of tradenames. See Note 12 — Property Impairments, in the Notes to Financial Statements, for additional information. Accretion on discounted liabilities increased $123 million in 2003, reflecting accretion expense on environmental liabilities assumed in the merger and discounted obligations associated with the retirement and removal of long-lived assets that became effective January 1, 2003, with the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” See Note 2 — Changes in Accounting Principles, in the Notes to Financial Statements, for additional information on SFAS No. 143. In addition to the merger impact, interest and debt expense also increased in 2003 because of the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities,” (FIN 46). The adoption of FIN 46 for variable interest entities involving synthetic leases and certain other financing structures, effective January 1, 2003, resulted in increased balance sheet debt, which resulted in higher interest expense in 2003. See Note 2 — Changes in Accounting Principles, and Note 14 — Debt, in the Notes to Consolidated Financial Statements, for additional information. 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 7 — Subsidiary Equity Transactions, in the Notes to Consolidated Financial Statements, for additional information. Our effective tax rate in 2003 was 45 percent, compared with 67 percent in 2002. The lower effective tax rate in 2003 primarily was the result of a higher proportion of income in lower-tax-rate jurisdictions and the one-time impact of tax law changes in certain international jurisdictions. Contributing to the higher effective tax rate in 2002 was a write-off of in-process research and development costs, as well as the partial impairment of an exploration prospect, both without corresponding tax benefits in 2002. Our discontinued operations had income of $237 million in 2003, compared with a net loss of $993 million in 2002. The net loss in 2002 reflected charges totaling $1,008 million after-tax related to the impairment of properties, plants and equipment; goodwill; intangible assets; and provisions for losses associated with various operating lease commitments. For additional information about our discontinued operations, see Note 4 — Discontinued Operations, in the Notes to Consolidated Financial Statements. We adopted SFAS No. 143 effective January 1, 2003, resulting in the recognition of a benefit of $145 million for the cumulative effect of this accounting change. Also effective January 1, 2003, we adopted FIN 46 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. Together, these resulted in a net charge of $95 million. For additional information on these accounting changes, see Note 2 — Changes in Accounting Principles, in the Notes to Consolidated Financial Statements. 2002
vs. 2001 Restructuring
Accruals Segment
Results 2003
vs. 2002 Net income from the E&P segment increased 146 percent in 2003, compared with 2002. The improvement reflects higher production volumes, primarily due to the merger; higher crude oil and natural gas prices; and an increased net gain on asset sales. These items were partially offset by higher production and operating expenses; depreciation, depletion and amortization; and taxes other than income taxes, all the result of the larger size and scope of our operations following the merger. In addition, 2003 included benefits of $233 million in our international E&P operations from changes in income tax and site restoration laws, as well as an equity realignment of certain Australian operations. Also, the cumulative effect of the adoption of SFAS No. 143 and the adoption of FIN 46 for variable interest entities involving synthetic leases and certain other financing structures increased E&P’s net income by $142 million in 2003. Our average worldwide crude oil sales price was $27.47 per barrel in 2003, compared with $24.07 in 2002. We also benefited from higher natural gas prices in 2003, with our average worldwide price increasing from $2.77 per thousand cubic feet in 2002 to $4.07 in 2003. If crude oil and natural gas prices in 2004 do not remain at the historically strong levels experienced in 2003, E&P’s earnings will be negatively impacted in 2004. See the “Outlook” section for additional discussion of crude oil and natural gas prices. ConocoPhillips’ proved reserves at year-end 2003 were 7.85 billion barrels of oil equivalent, a slight increase over 7.81 billion barrels at year-end 2002. Our Canadian Syncrude mining operations had an additional 265 million barrels of proved oil sands reserves at the end of 2003, compared with 272 million barrels at year-end 2002. 2002
vs. 2001 Our proved reserves at year-end 2002 were 7.81 billion barrels of oil equivalent, a 52 percent increase over year-end 2001’s 5.13 billion barrels of oil equivalent. The increase was attributable to the merger. U.S.
E&P Our E&P Lower 48 net income increased $643 million in 2003, primarily because of increased natural gas production and sales prices, as well as, to a lesser extent, higher crude oil production and prices. U.S. Lower 48 natural gas prices increased 71 percent in 2003. Our increased production volumes in the Lower 48 mainly were the result of the merger, partially offset by the impact of asset dispositions. We continued our Lower 48/Gulf of Mexico asset rationalization program in 2003, which resulted in the sale of properties that did not fit into our long-term growth strategy. As planned, we are exiting the shallow water areas of the Gulf of Mexico. The Lower 48 operations recognized a net $1 million charge from the cumulative effect of adopting SFAS No. 143 and FIN 46 effective January 1, 2003. 2002
vs. 2001 Our U.S. crude oil production decreased slightly in 2002, while natural gas production increased 20 percent. The increase in natural gas production was mainly due to four months of production from fields acquired in the merger. The merger impact on total crude oil production was offset by lower production in Alaska, which experienced normal field declines, along with operating interruptions at the Prudhoe Bay field. International
E&P International E&P’s production on a barrel-of-oil-equivalent basis averaged 916,000 barrels per day in 2003, compared with 482,000 barrels per day in 2002. In addition, our Syncrude mining operations produced 19,000 barrels per day in 2003, compared with 8,000 barrels per day in 2002. Although the merger was the primary reason for the production increase, other items impacting our production rate in 2003 were:
Included in international E&P’s net income in 2003 was a net foreign currency transaction loss of $50 million, compared with a net loss of $34 million in 2002. International E&P’s net income in 2003 also was favorably impacted by the following items:
2002
vs. 2001 Our international crude oil production increased 64 percent in 2002, while natural gas production increased 126 percent. The increases were mainly due to the addition of four months of production from fields acquired in the merger. Midstream 2003
vs. 2002 Our Midstream segment consists of a 30.3 percent interest 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, Canada and Trinidad. Net income from the Midstream segment increased 136 percent in 2003, compared with 2002. The increase primarily was attributable to improved results from DEFS and the addition of midstream operations following the merger. DEFS’ results mainly increased because of higher natural gas liquids prices in 2003. In addition, DEFS’ results in 2002 included higher costs for gas imbalance adjustment accruals. Included in the Midstream segment’s 2003 net income was a basis-difference benefit of $36 million, compared with $35 million in 2002, 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. 2002
vs. 2001 Included in the Midstream segment’s net income in 2002 was a benefit of $35 million, representing the amortization of the basis difference between the book value of ConocoPhillips’ contribution to DEFS and our 30.3 percent equity interest in DEFS. The corresponding amount for 2001 was $36 million. R&M 2003
vs. 2002 Net income from our R&M segment increased substantially in 2003, compared with 2002. The improved results primarily were due to significantly higher U.S. refining margins. The addition of refining and marketing assets in the merger also contributed to the higher 2003 earnings, as did increased wholesale gasoline margins. Partially offsetting the improvements was a net charge of $125 million for the cumulative effect of the adoption of FIN 46 for variable interest entities involving synthetic leases and certain other financing structures. Our refineries produced 2.7 million barrels per day of petroleum products in 2003, compared with 2.0 million barrels per day in 2002. The increase reflects the addition of production from refineries acquired in the merger. 2002
vs. 2001 Worldwide crude oil refining capacity utilization was 90 percent in 2002, compared with 94 percent in 2001. Our refineries produced 2.0 million barrels per day of petroleum products in 2002, compared with 814,000 barrels per day in 2001. The increase reflects a full year of operations for refineries acquired in the Tosco acquisition and four months of operations for the refineries acquired in the merger. U.S.
R&M The addition of refining and marketing assets in the merger also contributed to the higher 2003 earnings, as did increased wholesale gasoline margins. Partially offsetting the margin improvements in 2003 was a net charge of $125 million for the cumulative effect of the adoption of FIN 46 for variable interest entities involving synthetic leases and certain other financing structures, along with higher utility costs. For the full year of 2003, our U.S. refineries ran at a crude oil capacity utilization rate of 96 percent, compared with 91 percent in 2002. The rate in 2002 was lowered by higher maintenance turnaround activity, the impact of tropical storms on our Gulf Coast refineries, and the loss of Venezuelan crude oil supply in the fourth quarter due to the economic and political instability in that country during the quarter. 2002
vs. 2001 International
R&M Our international crude oil capacity utilization rate was 87 percent in 2003, compared with 78 percent in 2002. The lower utilization rate in 2002 primarily was the result of the Humber refinery in the United Kingdom being shut down for an extended period of time in the fourth quarter due to a power outage and subsequent downtime. 2002
vs. 2001 Chemicals 2003
vs. 2002 As the results in both years indicate, the chemicals industry continues to be challenged to effectively utilize capacity, manage costs and improve margins in a difficult economic environment. The worldwide chemicals industry experienced an economic downturn beginning in the second half of 2000, and the downturn continued through 2003. The downturn has led to excess production capacity in the industry and pressured margins on key products. The chemicals industry has also been impacted by high energy prices, which negatively impacts both utility and feedstock costs. 2002
vs. 2001 Due to depressed economic conditions in the chemicals industry, asset retirements and impairments totaling $84 million after-tax were recognized by CPChem in 2001. A developmental reactor at the Pasadena Plastics Complex in Pasadena, Texas, was retired; accelerated depreciation was recognized by CPChem on two polyethylene reactors at the Orange chemical plant in Orange, Texas; an ethylene unit was retired at the Sweeny complex in Old Ocean, Texas; an equity affiliate of CPChem recorded a property impairment related to a polypropylene facility; property impairments were taken on the manufacturing facility in Puerto Rico; and the benzene and cyclohexane units at the Puerto Rico facility were retired. In addition, the valuation allowance on the Puerto Rico facility’s deferred tax asset related to its net operating losses was increased in 2001 so that the deferred tax assets were fully offset by valuation allowances. Partially offsetting these impairments and retirements was a business interruption insurance settlement recognized by CPChem, and a favorable deferred tax adjustment recorded by ConocoPhillips related to the Puerto Rico facility, together totaling $57 million after-tax. Emerging
Businesses 2003
vs. 2002 2002
vs. 2001 Corporate
and Other 2003
vs. 2002 After-tax corporate general and administrative expenses were the same in 2003 as in 2002. Expenses in 2003 were impacted by the merger, as well as the expensing of stock options. Beginning in 2003, on a prospective basis, we elected to use the fair-value accounting method provided for under SFAS No. 123, “Accounting for Stock-Based Compensation.” Offsetting these items were increased allocations of certain staff costs to the operating segments in 2003. The increased corporate allocations did not have a material impact on the operating segments’ results. Income from discontinued operations was $237 million in 2003, compared with a loss of $993 million in 2002. The net loss in 2002 reflects charges totaling $1,008 million after-tax related to the impairment of properties, plants and equipment; goodwill; intangible assets; and provisions for losses associated with various operating lease commitments. For additional information about our discontinued operations, see Note 4 — Discontinued Operations, in the Notes to Consolidated Financial Statements. On an after-tax basis, merger-related costs were $223 million in 2003, compared with $307 million in 2002. Included in these costs were employee relocation expenses, transition labor costs, and other charges directly associated with the merger. 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 improved in 2003 because of higher foreign currency transaction gains and an after-tax gain of $34 million in the first quarter of 2003, representing beneficial interests we had in certain insurance companies as a result of the conversion of those companies from mutual companies to stock companies, a process known as demutualization. These beneficial interests arose from our prior purchase and ownership of various insurance policies and contracts issued by the mutual companies. Prior to the demutualizations, our mutual ownership interests in these insurance companies were not recognized because the ownership interests in the mutual companies were neither capable of valuation nor marketable. Included in Other in 2003 was a net foreign currency transaction gain of $67 million, after-tax, compared with a net gain of $21 million in 2002. 2002
vs. 2001 |
