Hess - 10-Q quarterly report FY

Results of Operations

      Net income for the third quarter of 2003 amounted to $146 million compared with a net loss of $136 million in the third quarter of 2002. Income in the third quarter of 2003 included an income tax benefit of $30 million reflecting the recognition for United States income tax purposes of certain prior year foreign exploration expenses. Results for the third quarter of 2002 included an after-tax impairment charge of $207 million ($318 million before income taxes). Net income for the first nine months of 2003 was $574 million compared with $153 million in the first nine months of 2002. The after-tax results by major operating activity for the three- and nine-months ended September 30, 2003 and 2002 were as follows (in millions, except per share data):

      In the discussion which follows, the financial effects of certain transactions are disclosed on an after-tax basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its explanation of variances in segment earnings. Such after-tax amounts may be considered to be non-GAAP financial measures. Management believes that they are a preferable method of explaining variances in earnings, since they show the entire effect of a transaction rather than only the pre-tax amount. After-tax amounts are determined by applying the appropriate income tax rate in each tax jurisdiction to pre-tax amounts.

Results of Operations (Continued)

Exploration and Production

      Exploration and production earnings from continuing operations include the following after-tax items in the third quarter and first nine months of 2003 and 2002 (in millions):

      The following table contains the pre-tax amounts of the items included above on an after-tax basis:

      After reflecting the after-tax variances in the table above, exploration and production earnings in the third quarter and first nine months of 2003 decreased by $62 million and $210 million compared with the corresponding periods of 2002. These decreases were primarily due to lower crude oil and natural gas sales volumes.

Results of Operations (Continued)

      The Corporation’s average selling prices from continuing operations, including the effects of hedging, were as follows:

The Corporation’s net daily worldwide production was as follows (in thousands):

Results of Operations (Continued)

      The Corporation’s oil and gas production, on a barrel-of-oil equivalent basis, decreased by 23% in the third quarter and 17% in the first nine months of 2003 compared with the corresponding periods of 2002. Approximately one-half of the decreases are due to asset sales and the Colombia/JDA exchange. The remainder of the decreases are principally due to natural decline in the United States and North Sea and reduced production from the Ceiba Field in Equatorial Guinea.

      In the third quarter of 2003, the Corporation exchanged its 25% equity investment in Premier Oil Plc for a 23% interest in the Indonesian Natuna A Field. In the fourth quarter, the Corporation has also exchanged 14% interests in the Scott and Telford fields in the United Kingdom for an additional 22.5% interest in the Llano Field in the Gulf of Mexico, plus $17 million in cash. Production from the Llano Field is scheduled to commence mid-year 2004.

      These transactions along with asset sales and the Colombia/JDA exchange in the first half of the year will contribute to a decline in production in 2004. Production in 2004 is expected to be approximately 12% below projected full year 2003 production of approximately 370 thousand barrels of oil equivalent per day. Approximately 40% of the decline is due to asset sales and exchanges and the remainder is due to natural decline.

      Production expenses increased in the third quarter and first nine months of 2003 compared with 2002, reflecting higher per barrel costs, including increased transportation, insurance and workover costs. Depreciation, depletion and amortization charges were lower in the third quarter and first nine months of 2003 principally reflecting lower production volumes. General and administrative expenses relating to exploration and production activities were comparable in the third quarter of 2003 and 2002, but higher in the first nine months of 2003, largely due to 2003 charges for accrued severance in London, Aberdeen and Houston and costs of a reduction in leased office space in London. Exploration expense was lower in the third quarter of 2003 compared with 2002, reflecting the timing of exploration drilling and higher capitalization of drilling costs in the 2003 quarter.

      After-tax foreign currency losses amounted to $3 million ($2 million gain before income taxes) in the third quarter of 2003 and $16 million ($15 million before income taxes) in the first nine months of 2003, compared with income of $11 million and $15 million ($6 million and $25 million before income taxes) in the corresponding periods of 2002. The pre-tax amounts of foreign currency gains and losses are included in non-operating income (expense) in the income statement.

      The effective income tax rate for exploration and production operations in the first nine months of 2003 was 52%. This rate includes income taxes in excess of the United States statutory rate in several producing areas, such as the United Kingdom and Norway. It also reflects the income tax deduction for the Corporation’s hedging results at only the U.S. statutory rate. In addition, certain expenses in foreign jurisdictions are not deductible for income tax purposes, or are benefited at rates equal to or below the U.S. statutory rate. Each of these factors

Results of Operations (Continued)

increases the Corporation’s overall exploration and production effective income tax rate. The full year 2003 exploration and production effective income tax rate is expected to be comparable to the rate for the first nine months of the year.

      The Corporation’s future exploration and production earnings may be impacted by volatility in the selling prices of crude oil and natural gas, reserve and production changes, fluctuations in foreign exchange rates and changes in tax rates.

Refining and Marketing

      Refining and marketing income amounted to $89 million in the third quarter of 2003 compared with $70 million in the corresponding period of 2002. For the first nine months of 2003, refining and marketing earnings were $272 million compared with income of $65 million in 2002. Refining and marketing earnings include the following after-tax items in the third quarter and first nine months of 2003 and 2002 (in millions):

      HOVENSA

      The Corporation’s share of HOVENSA’s income was $43 million in the third quarter of 2003 compared with a loss of $6 million in the third quarter of 2002. The Corporation’s share of HOVENSA’s income in the first nine months of 2003 was $108 million compared with a loss of $50 million in the first nine months of 2002. The increase was due to higher refining margins and sales volumes in both periods compared to the prior year. Income taxes on the Corporation’s share of HOVENSA’s results are not recorded due to available loss carryforwards.

      The Corporation’s share of HOVENSA’s crude runs amounted to 218,000 barrels per day in the first nine months of 2003 compared with 175,000 barrels per day in the first nine months of 2002. The fluid catalytic cracking unit at HOVENSA was shutdown for a portion of the first half of 2002. Crude runs were reduced in 2002 due to downtime at this unit and low refining margins. HOVENSA is currently

Results of Operations (Continued)

receiving its contracted quantities of crude oil from PDVSA after political disturbances in Venezuela earlier in the year interrupted crude oil deliveries.

      Refining and marketing earnings also included interest income of $23 million (before and after income taxes) in the first nine months of 2003 and $27 million in the first nine months of 2002 on the note received from PDVSA V.I. in connection with the formation of the joint venture.

      Retail, energy marketing and other

      Retail gasoline operations were more profitable in the third quarter and first nine months of 2003 than in the corresponding periods of 2002, reflecting higher margins and increased sales volumes at gasoline stations. Earnings from energy marketing activities were also higher in the third quarter and first nine months of 2003. Energy marketing earnings were particularly strong during the early part of 2003 reflecting increased margins and sales volumes from the colder winter. Results of the Port Reading refining facility also improved in 2003 compared with 2002, reflecting improved refining margins.

      Total refined product sales volumes increased by 11% to 114 million barrels in the first nine months of 2003 compared with the same period of 2002. The increase was largely due to higher demand for distillates and residual fuel oils.

      The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and energy derivatives. The Corporation also takes trading positions in addition to its hedging program. The Corporation’s after-tax results from trading activities, including its share of the earnings of the trading partnership, amounted to income of $3 million ($8 million before income taxes) in the third quarter of 2003 and income of $15 million ($26 million before income taxes) in the first nine months of 2003. Trading activities resulted in losses of $14 million ($20 million before income taxes) in the third quarter of 2002 and income of $4 million ($8 million before income taxes) in the first nine months of 2002.

      Refining and marketing earnings will likely continue to be volatile reflecting competitive industry conditions and supply and demand factors, including the effects of weather.

Corporate

      Net corporate expenses were $25 million in the third quarter and $73 million in the first nine months of 2003, compared with $23 and $56 million in the same periods of 2002. Corporate expenses in the first nine months of 2003 include after-tax charges of $15 million ($27 million before income taxes) from early repayment of debt. The amount in the corresponding period of 2002 was $4 million ($10 million before income taxes). The pre-tax expense for early debt repayment is recorded in other non-operating income (expense) in the income statement.

Results of Operations (Continued)

Interest

      After-tax interest expense amounted to $42 million in the third quarter of 2003 compared with $36 million in the third quarter of 2002 ($73 million and $61 million before income taxes, respectively). In the first nine months of 2003, after-tax interest expense amounted to $132 million compared with $127 million in the same period of 2002 ($224 million and $194 million before income taxes). Interest incurred in the third quarter and first nine months of 2003 was lower than in 2002 because of debt reduction, however, the reduction in interest incurred was more than offset by lower interest capitalized in 2003. Pre-tax capitalized interest amounted to $31 million in the first nine months of 2003 compared with $75 million in the corresponding period of 2002.

Discontinued Operations

      In the first quarter of 2003, the Corporation exchanged its crude oil producing properties in Colombia, plus $10 million in cash, for an additional 25% interest in Block A-18 in the joint development area of Malaysia and Thailand. The exchange resulted in an after-tax charge to income in the first quarter of 2003 of $47 million ($51 million before income taxes), which the Corporation reported as a loss from discontinued operations. The loss on this exchange included a $43 million adjustment of the book value of the Colombian assets to fair value. The loss also included $17 million from the recognition in earnings of the value of related hedge contracts at the time of the exchange. These items were partially offset by after-tax earnings in Colombia prior to the exchange of $13 million.

      In the second quarter of 2003, the Corporation sold Gulf of Mexico Shelf properties, the Jabung Field in Indonesia and several small United Kingdom fields for $445 million. An after-tax gain from these asset sales of $175 million ($248 million before income taxes) was included in discontinued operations in the second quarter of 2003. Discontinued operations in the first nine months of 2003 also includes $40 million of income from operations prior to the sales of these assets.

Change in Accounting Principle

      The Corporation adopted FAS No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. A net after-tax gain of $7 million resulting from the cumulative effect of this accounting change was recorded at the beginning of the year. At the date of adoption, a liability of $556 million representing the estimated fair value of the Corporation’s required dismantlement obligations was recorded on the balance sheet. In addition, a dismantlement asset of $311 million was recorded, as well as accumulated depreciation of $203 million.

Results of Operations (Continued)

Consolidated Operating Revenues

      Sales and other operating revenues increased by 19% in the third quarter and 28% in the first nine months of 2003, compared with the corresponding periods of 2002. These increases principally reflect higher sales volumes of refined products and the increased selling price of purchased natural gas in energy marketing operations.

Liquidity and Capital Resources

      Net cash provided by operating activities, including changes in operating assets and liabilities, amounted to $1,159 million in the first nine months of 2003 compared with $1,427 million in the first nine months of 2002.

      In 2003, the Corporation has taken initiatives to reshape its portfolio of producing assets to reduce future costs, lengthen its reserve to production ratio, and provide capital for investment in new fields and funds to reduce debt. The Corporation exchanged producing properties in Colombia for an increased interest in a non-producing property under development in the joint development area of Malaysia and Thailand. The Corporation’s Colombia properties (acquired in 2001 as part of the Triton acquisition), plus $10 million in cash, were exchanged for an additional 25% interest in natural gas reserves in the joint development area of Malaysia and Thailand (JDA). The JDA production facilities are complete, but production will not commence until the construction of a natural gas pipeline and gas plant is completed by the purchasers of the gas. It is anticipated that production will begin in late 2005. The Corporation also sold certain producing properties in the Gulf of Mexico Shelf, the Jabung Field in Indonesia, several small United Kingdom fields and an interest in a shipping joint venture. The aggregate proceeds from these sales were $508 million. The net production from fields sold or exchanged at the time of disposition was approximately 45,000 barrels of oil equivalent per day.

      In the third quarter of 2003, the Corporation completed the exchange of its 25% equity investment in Premier Oil plc for a 23% interest in Natuna Sea Block A in Indonesia, plus approximately $10 million in cash (including closing adjustments). Current production from the Corporation’s 23% interest in Natuna is approximately 5,000 barrels of oil equivalent per day.

      In October 2003, the Corporation exchanged 14% interests in the Scott and Telford fields in the United Kingdom for an additional 22.5% interest in the Llano Field in the Gulf of Mexico and $17 million in cash. The exchange increases the Corporation’s working interest in the Llano Field to 50% and decreases its interest in the Scott Field to 21% and the Telford Field to 17%. Production from the United Kingdom interests being transferred was approximately 10,000 barrels per day in the third quarter of 2003. Production from the Corporation’s 50% interest in the Llano Field is scheduled to commence in the second quarter of 2004.

Liquidity and Capital Resources (Continued)

      The asset sales accelerated cash flows into 2003 that would have been received over the productive lives of the assets. The proceeds from asset sales, as well as operating cash flow, will provide capital for the development of new fields, as well as funds to repay debt. The Corporation believes the overall impact of its program of asset sales and exchanges of properties has not reduced its liquidity in the short-term or over the next five years.

      Based on current estimates of production, capital expenditures and other variables, and assuming quarter-end oil and gas prices, the Corporation anticipates it will fund its future operations, including capital expenditures and required debt repayment, with cash flow from operations, and, when necessary, available borrowing capacity under its presently undrawn, committed revolving credit agreement totaling $1.5 billion, and proceeds of issuances of securities under the shelf registration described below. The Corporation’s revolving credit agreement expires in 2006 and the Corporation expects it will be able to arrange a new committed facility at that time, if required. It is possible that there will be a modest increase in total debt over the next five quarters.

      On November 6, 2003, the Corporation filed a shelf registration statement on Form S-3. This registration, when effective, will allow the Corporation to issue from time to time the following securities: debt securities, shares of common stock, shares of preferred stock and warrants to purchase common stock, preferred stock or debt securities. The aggregate initial offering price of all securities that could be issued by the Corporation under the registration statement will not exceed $1,500 million. The proceeds, if any, will be used for general corporate purposes, which may include working capital, capital expenditures, acquisitions and the reduction or refinancing of existing indebtedness.

      Total debt decreased by $502 million at September 30, 2003 from $4,992 million at December 31, 2002. The Corporation’s debt to capitalization ratio was 48.8% at September 30, 2003 compared with 54.0% at December 31, 2002.

      At September 30, 2003, loan agreement covenants allow the Corporation to borrow an additional $3.3 billion for the construction or acquisition of assets. The amount that can be borrowed under the loan agreements for the payment of dividends is $1.2 billion. At September 30, 2003, the Corporation has $1.5 billion of additional borrowing capacity available under its revolving credit agreement and has additional unused lines of credit for $206 million under uncommitted arrangements with banks.

      The Corporation has lease financings, a portion of which are leveraged lease financings not included in its balance sheet, primarily related to retail gasoline stations. The net present value of the financings is $462 million at September 30, 2003, using interest rates inherent in the leases. The Corporation’s September 30 debt to capitalization ratio would increase from 48.8% to 51.2% if the lease financings were included.

Liquidity and Capital Resources (Continued)

      While the Corporation continues to maintain investment grade credit ratings, two rating agencies have reduced their ratings of the Corporation’s debt during 2003. The rating changes did not result in the termination or reduction of any of the Corporation’s debt or leasing capacity, nor were principal or interest payments accelerated. The Corporation’s commercial paper ratings have also been reduced, which has restricted its ability to access the commercial paper market. However, it has $1.5 billion in unused revolving credit capacity available. Certain contracts with hedging and trading counterparties require additional cash margin or collateral of up to approximately $43 million because of the downgrade. The Corporation estimates the change in credit ratings increased financing costs by less than $1 million annually.

      In October 2003, one rating agency placed the Corporation’s long-term debt and commercial paper ratings under review for possible downgrade. If the Corporation’s credit rating were to be reduced by this agency below investment grade, the Corporation may be required to provide additional security under a lease with remaining payments of $39 million and to comply with more stringent financial covenants contained in debt instruments assumed in the Triton acquisition, unless it elects to defease these obligations. The Corporation would have been in compliance with such covenants as of the balance sheet date. In addition, the amount of cash margin or collateral required under contracts with hedging and trading counterparties at September 30, 2003 would increase by approximately $64 million. A downgrade below investment grade would increase annual financing costs by $5 million.

      The Corporation and PDVSA equally guarantee the payment of the value of HOVENSA’s crude oil purchases from suppliers other than PDVSA. The amount of the Corporation’s guarantee fluctuates based on the volume of crude oil purchased and related prices and at September 30, 2003 amounted to $96 million.

      In addition, the Corporation has agreed to provide funding, in proportion to its 50% interest, to the extent HOVENSA does not have funds to meet its senior debt obligations prior to coker financial completion, as defined. At September 30, 2003, the Corporation’s pro-rata share of HOVENSA’s senior debt was $84 million after deducting HOVENSA funds available for debt service. In October 2003, coker financial completion was achieved and the maximum pro-rata share of funding became $40 million. After completion of construction required to meet final low sulfur fuel regulations, this amount reduces to $15 million.

      In connection with the sale of six vessels in 2002, the Corporation agreed to support the buyer’s charter rate on these vessels for up to five years. The support agreement requires that if the actual contracted rate for the charter of a vessel is less than the stipulated support rate in the agreement the Corporation will pay to the buyer the difference between the contracted rate and the stipulated rate. At January 1, 2003, the charter support reserve was $48 million. During the first nine months of 2003, the Corporation paid $3 million of charter support, reducing the reserve to $45 million.

Liquidity and Capital Resources (Continued)

      In the second quarter of 2003, the Corporation recorded an after-tax charge of $23 million for accrued severance and a reduction in leased office space in London. The pre-tax amount of this charge was $38 million, of which $21 million relates to leased office space. The remainder of $17 million relates to severance for positions that were eliminated in London, Aberdeen and Houston. Through September 30, approximately $4 million of the severance has been paid. Over 700 employee and contractor positions have been or will be eliminated or will be transferred to other operators. Approximately 280 employees will be receiving severance, which will be paid principally in the fourth quarter and 2004. Additional accruals for severance and lease costs of approximately $22 million before income taxes are anticipated over the next several quarters. The estimated annual savings from this cost reduction initiative is approximately $50 million before income taxes.

      Capital expenditures in the first nine months of 2003 were $1,015 million of which $958 million related to exploration and production activities. Capital expenditures in the first nine months of 2002 were $1,207 million, including $1,101 million for exploration and production. Capital expenditures for the remainder of 2003 are currently estimated to be approximately $420 million. These expenditures are expected to be funded by available cash or cash flow from operations. Capital expenditures in 2004 excluding acquisitions, if any, are currently expected to be $1.5 billion.

Market Risk Disclosure

      In the normal course of business, the Corporation is exposed to commodity risks related to changes in the price of crude oil, natural gas, refined products and electricity. In the disclosures that follow, these operations are referred to as non-trading activities. The Corporation also has trading operations, principally through a 50% voting interest in a trading partnership. These activities are also exposed to commodity risks principally related to the prices of crude oil, natural gas and refined products.

      Instruments: The Corporation uses forward commodity contracts, foreign exchange forward contracts, futures, swaps and options in the Corporation’s non-trading and trading activities. These contracts are widely traded instruments with standardized terms.

      Quantitative Measures: The Corporation uses value-at-risk to monitor and control commodity risk within its trading and non-trading activities. The value-at-risk model uses historical simulation and the results represent the potential loss in fair value over one day at a 95% confidence level. The model captures both first and second order sensitivities for options. The potential change in fair value based on commodity price risk is presented in the non-trading and trading sections below.

      Non-Trading: The Corporation’s non-trading activities include hedging of crude oil and natural gas production. Futures and swaps are used to fix the selling prices

Market Risk Disclosure (Continued)

of a portion of the Corporation’s future production and the related gains or losses are an integral part of the Corporation’s selling prices. As of September 30, the Corporation has open hedge positions equal to 60% of its estimated 2003 worldwide crude oil production for the period October 1, 2003 to December 31, 2003, 60% of estimated 2004 worldwide crude oil production and 15% of estimated 2005 production. The average price for West Texas Intermediate (WTI) related open hedge positions is $26.38 in 2003, $24.62 in 2004 and $25.03 in 2005. The average price for Brent related open hedge positions is $24.34 in 2003, $23.74 in 2004 and $23.79 in 2005. Approximately 15% of the Corporation’s hedges are WTI related and the remainder are Brent. The Corporation has no open hedges of natural gas production at September 30, 2003. As market conditions change, the Corporation may adjust its hedge positions.

      The Corporation also markets energy commodities including refined petroleum products, natural gas and electricity. The Corporation uses futures and swaps to fix the purchase prices of commodities to be sold under fixed-price sales contracts.

      The Corporation estimates that at September 30, 2003, the value-at-risk for commodity related derivatives that are settled in cash and used in non-trading activities was $41 million ($50 million at December 31, 2002). The results may vary from time to time as hedge levels change.

      Trading: The trading partnership in which the Corporation has a 50% voting interest trades energy commodities and derivatives. The accounts of the partnership are consolidated with those of the Corporation. The Corporation also takes trading positions for its own account. These strategies include proprietary position management and trading to enhance the potential return on assets. The information that follows represents 100% of the trading partnership and the Corporation’s proprietary trading accounts.

      In trading activities, the Corporation is exposed to changes in crude oil, natural gas and refined product prices, primarily in North America and Europe. Trading positions include futures, swaps and options. In some cases, physical purchase and sale contracts are used as trading instruments and are included in the trading results.

      Derivative trading transactions are marked-to-market and are reflected in income currently. Total net realized gains, before income taxes, for the first nine months of 2003 amounted to $35 million and net unrealized gains were $68 million. The following table provides a compilation of the factors affecting the changes in fair value of trading contracts in the first nine months of 2003 and represents 100% of the trading partnership and other trading activities (in millions):

Market Risk Disclosure (Continued)

      The Corporation uses observable market values for determining the fair value of its trading instruments. The majority of valuations are based on actively quoted market values. In cases where actively quoted prices are not available, other external sources or internal estimates are used. External sources incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. The Corporation’s risk management department compares valuations regularly to independent sources and models. The sources of fair value at September 30, 2003 follow (in millions):

      The Corporation estimates that at September 30, 2003, the value-at-risk for trading activities, including commodities, was $9 million ($6 million at December 31, 2002). The results may change from time to time as strategies change to capture potential market rate movements.

      The following table summarizes the fair values of net receivables, including option premiums, relating to the Corporation’s trading activities and the credit rating of counterparties at September 30, 2003 (in millions):

Critical Accounting Policies

      Accounting policies affect the recognition of assets and liabilities on the Corporation’s balance sheet and revenues and expenses on the income statement. The accounting methods used can affect net income, stockholders’ equity and various financial statement ratios. However, the Corporation’s accounting policies generally do not change cash flows or liquidity.

Critical Accounting Policies (Continued)

      As explained below there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing. The Corporation reviews long-lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long-lived assets are tested at the lowest level for which cash flows are identifiable and are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.

      In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes of individual fields and discounted at a rate commensurate with the risks involved. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of actual prices on the last day of the year.

      The Corporation’s impairment tests of long-lived exploration and production producing assets are based on its best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs and the timing of future production, which are updated each time an impairment test is performed. The Corporation could have impairments if the projected production volumes on oil and gas fields were reduced. Significant extended declines in crude oil and natural gas selling prices could also result in asset impairments.

      The Corporation has recorded $977 million of goodwill in connection with the purchase of Triton. Factors contributing to the recognition of goodwill included the strategic value of expanding global operations to access new growth areas outside of the United States and the North Sea, obtaining critical mass in Africa and Southeast Asia, and synergies, including cost savings, improved processes and portfolio high grading opportunities. In accordance with FAS No. 142, goodwill is no longer amortized but must be tested for impairment annually. FAS No. 142 requires that goodwill be tested for impairment at a reporting unit level. 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,

Critical Accounting Policies (Continued)

two or more components of an operating segment shall be aggregated and deemed a single reporting unit if the components have similar economic characteristics. An operating segment shall be deemed to be a reporting unit if all of its components are economically similar.

      Within the exploration and production operating segment there are currently two components: (1) Americas and West Africa and (2) Europe, North Africa and Asia. Each component has a manager who reports to the segment manager. The Corporation has determined the components have similar economic characteristics and, therefore, aggregates the components into a single reporting unit – the exploration and production operating segment. As a result, goodwill has been assigned to the exploration and production operating segment. If the Corporation reorganized its exploration and production business such that there was more than one operating segment or if its components were no longer economically similar, goodwill would be assigned to two or more reporting units. The goodwill would be allocated to any new reporting units using a relative fair value approach in accordance with FAS No. 142. Goodwill impairment testing for lower level reporting units could result in the recognition of an impairment that would not otherwise be recognized at the current higher level of aggregation.

      The Corporation expects that the benefits of goodwill will be recovered through the operation of the exploration and production segment as a whole and it evaluated the following characteristics in determining that the components are economically similar:

      The Corporation’s fair value estimate of the exploration and production segment is the sum of: (1) the discounted anticipated cash flows of producing assets and known developments, (2) the expected risked present value of exploration assets, and (3) an estimated market premium to reflect the market price an acquirer would pay for potential synergies including cost savings, access to new business opportunities, enterprise control, improved processes and increased market share. The Corporation also considers the relative market valuation of similar exploration and production companies.

      The determination of the fair value of the exploration and production operating segment depends on judgments about oil and gas reserves, future prices, timing of

Critical Accounting Policies (Continued)

future net cash flows and market premiums. The effect of synergies is embedded in the value of producing assets, known developments and exploration assets. Significant extended declines in crude oil and natural gas prices, reduced reserve estimates or failure to realize synergies could lead to a decrease in the fair value of the exploration and production operating segment that could result in an impairment of goodwill. In addition, changes in management structure or sales or dispositions of a portion of the exploration and production segment may result in goodwill impairment.

      As explained above, there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing. Consequently, there may be impairments of individual assets that would not cause an impairment of the $977 million of goodwill assigned to the exploration and production segment. In 2002, the Corporation recognized asset impairments because reduced estimates of oil and gas production volumes caused the expected undiscounted cash flows of the assets to be lower than the asset carrying amounts. No impairment of goodwill exists because the fair value of the overall exploration and production operating segment continues to exceed its recorded book value.

      The Corporation has two operating segments: (1) exploration and production and (2) refining and marketing. Management has determined that these are its operating segments because, in accordance with FAS No. 131, these are the segments of the Corporation (i) that engage in business activities from which revenues are earned and expenses are incurred, (ii) whose operating results are regularly reviewed by the Corporation’s chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance and (iii) for which discrete financial information is available. Mr. John B. Hess, Chairman of the Board and Chief Executive Officer of the Corporation, is the chief operating decision maker (“CODM”) as defined in FAS No. 131, because he is responsible for performing the functions within the Corporation of allocating resources to and assessing the performance of the Corporation’s operating segments. Mr. Hess uses only the operating results of each segment as a whole to make decisions about resources to be allocated to each segment and to assess the segment performance. The CODM manages each segment globally and does not regularly review the operating results of any component (e.g., geographic area) or asset within each segment or any information by geographical location, oil and gas property or project, subsidiary or division, to make decisions about resources to be allocated or to assess performance. While the CODM does review and approve initial corporate funding for a new project using information about the project, he does not review subsequent operating results by project after the initial funding. Each operating segment has one manager. The segment managers are responsible for allocating resources within the segments, reviewing financial results of components within the segments, and assessing the performance of the components. The CODM evaluates the performance of the segment managers based on performance metrics related to each manager’s operating segment as a whole. The Board of Directors of the Corporation does not receive more detailed information than that used by the CODM to operate and manage the Corporation.

Critical Accounting Policies (Continued)

      The oil and gas industry is currently discussing the appropriate balance sheet classification of oil and gas mineral rights held by lease or contract. The Corporation classifies these assets as property, plant and equipment in accordance with its interpretation of FAS No. 19 and common industry practice. There is also a view that these mineral rights are intangible assets as defined in FAS No. 141,Business Combinations, and, therefore, should be classified separately on the balance sheet as intangible assets. If the accounting for mineral rights held by lease or contract is ultimately changed, the Corporation believes that any such reclassification of mineral rights could amount to approximately $2.4 billion at September 30, 2003 and $2.2 billion at December 31, 2002, if the Corporation is required to include the purchase price allocated to hydrocarbon reserves obtained in acquisitions of oil and gas properties. The determination of this amount is based on the Corporation’s current understanding of this evolving issue and how the provisions of FAS No. 141 might be applied to oil and gas mineral rights. This potential balance sheet reclassification would not affect results of operations or cash flows.

Forward-Looking Information

      Certain sections of Management’s Discussion and Analysis of Results of Operations and Financial Condition, including references to the Corporation’s future results of operations and financial position, liquidity and capital resources, capital expenditures, oil and gas production, tax rates, debt repayment, hedging, derivative and environmental disclosures, represent forward-looking information. Forward-looking disclosures are based on the Corporation’s current understanding and assessment of these activities and reasonable assumptions about the future. Actual results may differ from these disclosures because of changes in market conditions, government actions and other factors.