Business description of HESS-CORPORATION

(Registrant’s telephone number, including area code, is (212) 997-8500)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant submitted electronically and posted on its Corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $17,579,000,000 computed using the outstanding common shares and closing market price on June 30, 2009.

At December 31, 2009, there were 327,229,488 shares of Common Stock outstanding.

Part III is incorporated by reference from the Proxy Statement for the annual meeting of stockholders to be held on May 5, 2010.

HESS CORPORATION

Form 10-K

TABLE OF CONTENTS

Item No.

Hess Corporation (the Registrant) is a Delaware corporation, incorporated in 1920. The Registrant and its subsidiaries (collectively referred to as the Corporation or Hess) is a global integrated energy company that operates in two segments, Exploration and Production (E&P) and Marketing and Refining (M&R). The E&P segment explores for, develops, produces, purchases, transports and sells crude oil and natural gas. These exploration and production activities take place principally in Algeria, Australia, Azerbaijan, Brazil, Colombia, Denmark, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia, Libya, Malaysia, Norway, Peru, Russia, Thailand, the United Kingdom and the United States. The M&R segment manufactures refined petroleum products and purchases, markets and trades, refined petroleum products, natural gas and electricity. The Corporation owns 50% of a refinery joint venture in the United States Virgin Islands. An additional refining facility, terminals and retail gasoline stations, most of which include convenience stores, are located on the East Coast of the United States.

Exploration and Production

The Corporation’s total proved developed and undeveloped reserves at December 31 were as follows:

Developed

United States

Europe

Africa

Asia and other

Undeveloped

Total

On a barrel of oil equivalent (boe) basis, 41% of the Corporation’s worldwide proved reserves are undeveloped at December 31, 2009 (43% at December 31, 2008). Proved reserves held under production sharing contracts at December 31, 2009 totaled 24% of crude oil and natural gas liquids and 57% of natural gas reserves (28% and 58% respectively, at December 31, 2008).

The Securities and Exchange Commission (SEC) revised its oil and gas reserve estimation and disclosure standards effective December 31, 2009. See the Supplementary Oil and Gas Data on pages 77 through 84 in the accompanying financial statements for additional information on the Corporation’s oil and gas reserves.

Worldwide crude oil, natural gas liquids and natural gas production was as follows:

Crude oil (thousands of barrels per day)

United States

Onshore

Offshore

Europe

United Kingdom

Norway

Denmark

Russia

Africa

Equatorial Guinea

Algeria

Gabon

Libya

Asia and other

Azerbaijan

Other

Total

Natural gas liquids (thousands of barrels per day)

Natural gas (thousands of mcf per day)

Joint Development Area of Malaysia/Thailand (JDA)

Thailand

Indonesia

Barrels of oil equivalent*

A description of our significant E&P operations follows:

United States

At December 31, 2009, 21% of the Corporation’s total proved reserves were located in the United States. During 2009, 24% of the Corporation’s crude oil and natural gas liquids production and 13% of its natural gas production were from United States operations. The Corporation’s production in the United States was principally from properties offshore in the Gulf of Mexico, which include the Shenzi (Hess 28%), Llano (Hess 50%), Conger (Hess 38%), Baldpate (Hess 50%), Hack Wilson (Hess 25%) and Penn State (Hess 50%) fields, as well as onshore properties in the Williston Basin of North Dakota and in the Permian Basin of Texas.

In the deepwater Gulf of Mexico, production commenced at the Shenzi Field in March 2009. Net production from Shenzi averaged approximately 25,000 barrels of oil equivalent per day (boepd) in 2009. The operator plans on drilling additional production wells at Shenzi in 2010.

In North Dakota, the Corporation holds a net acreage position in the Bakken shale play of approximately 510,000 acres. In 2009, the Corporation sanctioned a development program for the Bakken. The Corporation plans to expand production facilities and increase the rig count to 10 from 3 over the next 18 months, and invest about $1 billion per year over the next five years. As a result, the Corporation projects an increase in net production from approximately 10,000 boepd in 2009 to approximately 80,000 boepd in 2015.

The Corporation is developing a residual oil zone at the Seminole-San Andres Unit (Hess 34%) in Texas where carbon dioxide gas supplied from its interests in the West Bravo Dome and Bravo Dome fields in New Mexico is being injected to enhance recovery of crude oil.

At the Pony prospect on Green Canyon Block 468 (Hess 100%) in the deepwater Gulf of Mexico, engineering and design work for field development progressed during 2009. The Corporation plans to drill an appraisal well on Green Canyon Block 469 in 2010.

In 2009 the Corporation acquired rights to explore a total of more than 80,000 net acres in the Marcellus gas shale formation in Pennsylvania. The Corporation is operator and holds a 100% interest on approximately 50,000 acres and holds a 50% non-operated interest in the remaining acreage. Exploration drilling activity is expected to commence in 2010.

At December 31, 2009, the Corporation had interests in 331 total blocks in the Gulf of Mexico, of which 292 were exploration blocks comprising 1.1 million net undeveloped acres and the remainder were held for production and development operations.

Europe

At December 31, 2009, 30% of the Corporation’s total proved reserves were located in Europe (United Kingdom 8%, Norway 13%, Denmark 3% and Russia 6%). During 2009, 29% of the Corporation’s crude oil and natural gas liquids production and 22% of its natural gas production were from European operations.

United Kingdom: Production of crude oil and natural gas liquids from the United Kingdom North Sea was principally from the Corporation’s non-operated interests in the Nevis (Hess 39%), Schiehallion (Hess 16%), Clair (Hess 9%), Bittern (Hess 28%) and Beryl (Hess 22%) fields. Natural gas production from the United Kingdom was primarily from the Easington Catchment Area (Hess 32%), Bacton area (Hess 22%), Beryl (Hess 22%), Everest (Hess 19%), Lomond (Hess 17%), Nevis (Hess 39%), Atlantic (Hess 25%) and Cromarty (Hess 90%) fields. The operator plans to drill additional production wells at Beryl in 2010.

Norway: Substantially all of the 2009 and 2008 Norwegian production was from the Corporation’s interest in the Valhall Field (Hess 28%). A field redevelopment for Valhall commenced in 2007 and is expected to be completed in 2011. In 2010, the operator plans on drilling additional production and injection wells at Valhall. Additionally in 2010, the operator will continue to work on the Valhall Flank Gas Lift project, which was sanctioned in 2009 and is expected to be completed in 2011. The Corporation also holds an interest in the Snohvit (Hess 3%), Snorre (Hess 1%) and Hod (Hess 25%) fields. All four of the Corporation’s Norwegian field interests are located offshore.

In December 2009, the Corporation agreed to a strategic exchange of all of its interests in Gabon and the Clair Field in the United Kingdom for an additional 28% interest in Valhall and 25% interest in Hod. The transaction, which has an effective date of January 1, 2010, is subject to various regulatory and other approvals. In addition, the partners are in discussions regarding the applicability of pre-emption to this transaction.

Denmark: Crude oil and natural gas production comes from the Corporation’s interest in the South Arne Field (Hess 58%). In 2010, the Corporation plans a two well production drilling program.

Russia: The Corporation’s activities in the Russian Federation are conducted through its 80% interest in a subsidiary operating in the Volga-Urals region of Russia. As of December 31, 2009, this subsidiary had exploration and production rights in 13 license areas in the Samara Oblast. In December 2009 this subsidiary also secured rights in the Novomaliklinsky license area, which lies in the Ulyanovsk Oblast. Production currently comes from ten license areas, but exploration and development investment is planned in all 14 license areas.

Africa

At December 31, 2009, 23% of the Corporation’s total proved reserves were located in Africa (Equatorial Guinea 8%, Algeria 2%, Libya 11% and Gabon 2%). During 2009, 41% of the Corporation’s crude oil and natural gas liquids production was from African operations.

Equatorial Guinea: The Corporation is the operator and owns an interest in Block G (Hess 85%) which contains the Ceiba Field and Okume Complex. The Corporation plans to drill additional production wells at Okume in 2010.

Algeria: The Corporation has a 49% interest in a venture with the Algerian national oil company, that redeveloped three oil fields.

Libya: The Corporation, in conjunction with its Oasis Group partners, has oil and gas production operations in the Waha concessions in Libya (Hess 8%). The Corporation also owns a 100% interest in offshore exploration Area 54 in the Mediterranean Sea, where a successful exploration well was drilled in 2008. In 2009, the Corporation successfully flow tested the first exploration well and subsequently drilled and successfully flow tested a down-dip appraisal well. In 2010, the Corporation plans to reprocess 3D seismic, integrating acquired well information, and will continue technical and commercial evaluation of the block.

Gabon: The Corporation’s activities in Gabon are conducted through its wholly-owned Gabonese subsidiary, where the Corporation has interests in the Rabi Kounga, Toucan and Atora fields. In the fourth quarter of 2009, the Corporation agreed to a strategic exchange of all of its interests in Gabon for additional interests in the Valhall and Hod fields offshore Norway.

Egypt: The Corporation has an interest in the West Mediterranean Block 1 concession (West Med Block) (Hess 55%), which contains natural gas discoveries and additional exploration opportunities. The Corporation is currently evaluating technical and commercial options for this block and further exploratory drilling is planned. The Corporation also owns a 100% interest in Block 1 offshore Egypt in the Red Sea. During 2009 the Corporation acquired and completed the reprocessing of seismic data for this block.

Ghana: The Corporation holds a 100% interest in the Deepwater Tano Cape Three Points License. The Corporation is evaluating 3D seismic in anticipation of drilling the second exploration well on this prospect in late 2010 or early 2011.

Asia and Other

At December 31, 2009, 26% of the Corporation’s total proved reserves were located in the Asia and other region (JDA 11%, Indonesia 9%, Thailand 3%, Azerbaijan 2% and Malaysia 1%). During 2009, 6% of the Corporation’s crude oil and natural gas liquids production and 65% of its natural gas production were from Asia and other operations.

Joint Development Area of Malaysia/Thailand (JDA): The Corporation owns an interest in Block A-18 of the JDA (Hess 50%) in the Gulf of Thailand. Phase 2 gas sales commenced in November of 2008. In 2009, the Corporation acquired a 50% interest in Blocks PM301 and PM302 in Malaysia, which are adjacent to Block A-18 of the JDA.

Indonesia: The Corporation’s natural gas production in Indonesia primarily comes from its interests offshore in the Ujung Pangkah project (Hess 75%), which commenced production in 2007, and the Natuna A Field (Hess 23%). Additional production from a Phase 2 oil project at Ujung Pangkah commenced in 2009. The Corporation also owned an interest in the onshore Jambi Merang natural gas development project (Hess 25%), which was sold in January 2010. In May 2009, the Corporation obtained a 100% working interest in the offshore South Sesulu Block, where the Corporation is planning to acquire and process seismic in 2010. The Corporation also holds a 100% working interest in the offshore Semai V Block, where the Corporation is evaluating seismic and plans to drill an exploration well in late 2010 or early 2011.

Thailand: The Corporation’s natural gas production in Thailand primarily comes from the offshore Pailin Field (Hess 15%) and the onshore Sinphuhorm Block (Hess 35%).

Azerbaijan: The Corporation has an interest in the Azeri-Chriag-Gunashli (ACG) fields (Hess 3%) in the Caspian Sea. In 2010, production drilling will continue and the operator will seek sanction to install an additional production and drilling platform, which will include processing facilities and related infrastructure.

Australia: The Corporation holds a 100% interest in an exploration license covering 780,000 acres in the Carnarvon basin offshore Western Australia (WA-390-P Block). Through December 31, 2009, the Corporation has drilled 11 of the 16 commitment wells on the block, nine of which were natural gas discoveries. The Corporation plans to drill the remaining five commitment wells on the block in 2010. The Corporation also holds a 50% interest in WA-404-P Block located offshore Western Australia, which covers a total area of 680,000 acres. The operator completed a successful exploration well on this block in 2009 and plans to drill the remaining eight commitment wells on this block in 2010. In January 2010, the operator announced that the first well of the 2010 program discovered natural gas.

Brazil: The Corporation has interests in two blocks located offshore Brazil, BM-S-22 (Hess 40%) and BM-ES-30 (Hess 30%). In 2009, two exploration wells were completed on BM-S-22. A notice of discovery was filed for the first well and the second well was expensed. In 2010, the operator of BM-S-22 plans to commence drilling of a third exploration well in the second half of the year. In 2009, the Corporation also drilled an exploration well on BM-ES-30, which was expensed.

Peru: The Corporation has an interest in Block 64 in Peru (Hess 50%). At the end of 2009, the Corporation was drilling a sidetrack to an exploration well on this block. Further evaluation work is planned for 2010.

Colombia: The Corporation has interests in offshore Blocks RC 6 and RC 7 (Hess 30%). During 2009 the Corporation acquired 3D seismic for those blocks. Additional 3D seismic will be acquired and processed in 2010.

Oil and Gas Reserves

The Corporation’s net proved oil and gas reserves at the end of 2009, 2008 and 2007 are presented under the Supplementary Oil and Gas Data on pages 77 through 84 in the accompanying financial statements.

During 2009, the Corporation provided oil and gas reserve estimates for 2008 to the United States Department of Energy. Such estimates are consistent with the information furnished to the SEC on Form 10-K for the year ended

December 31, 2008, although not necessarily directly comparable due to the requirements of the individual requests. There were no differences in excess of 5%.

Sales commitments: The Corporation has no contracts or agreements to sell fixed quantities of its crude oil production. In the United States, natural gas is marketed by the M&R segment on a spot basis and under contracts for varying periods of time to local distribution companies, and commercial, industrial and other purchasers. The Corporation’s United States natural gas production is expected to approximate 30% of its 2010 sales commitments under long-term contracts. The Corporation attempts to minimize supply risks associated with its United States natural gas supply commitments by entering into purchase contracts with third parties having reliable sources of supply and by leasing storage facilities.

Outside of the United States and the United Kingdom, the Corporation generally sells its natural gas production under long-term sales contracts at prices that are periodically adjusted due to changes in commodity prices or other indices.

Average selling prices and average production costs

Average selling prices*

Crude oil (per barrel)

United States

Europe

Africa

Asia and other

Worldwide

Natural gas liquids (per barrel)

Natural gas (per mcf)

Average production (lifting) costs per barrel of oil equivalent produced**

The table above does not include costs of finding and developing proved oil and gas reserves, or the costs of related general and administrative expenses, interest expense and income taxes.

Gross and net undeveloped acreage at December 31, 2009

Total**

Gross and net developed acreage and productive wells at December 31, 2009

Total

Number of net exploratory and development wells drilled

Productive wells

Dry holes

Total

Number of wells in process of drilling at December 31, 2009:

Number of net waterfloods and pressure maintenance projects in process of installation at December 31, 2009 — 1

Marketing and Refining

Refining

The Corporation owns a 50% interest in HOVENSA L.L.C. (HOVENSA), a refining joint venture in the United States Virgin Islands with a subsidiary of Petroleos de Venezuela S.A. (PDVSA). In addition, it owns and operates a refining facility in Port Reading, New Jersey.

HOVENSA: Refining operations at HOVENSA consist of crude units, a fluid catalytic cracking unit (FCC) and a delayed coker unit.

The following table summarizes capacity and utilization rates for HOVENSA:

Crude

Fluid catalytic cracker

Coker

The delayed coker unit permits HOVENSA to run lower-cost heavy crude oil. HOVENSA has a long-term supply contract with PDVSA to purchase 115,000 barrels per day of Venezuelan Merey heavy crude oil. PDVSA also supplies 155,000 barrels per day of Venezuelan Mesa medium gravity crude oil to HOVENSA under a long-term crude oil supply contract. The remaining crude oil requirements are purchased mainly under contracts of one year or less from third parties and through spot purchases on the open market. After sales of refined products by HOVENSA to third parties, the Corporation purchases 50% of HOVENSA’s remaining production at market prices.

Gross crude runs at HOVENSA averaged 402,000 barrels per day in 2009 compared with 441,000 barrels per day in 2008 and 454,000 barrels per day in 2007. The 2009 and 2008 utilization rates for HOVENSA reflect weaker refining margins and planned and unplanned maintenance. The 2008 utilization rates also reflect a refinery wide shut down for Hurricane Omar. In January 2010, HOVENSA commenced a turnaround of its FCC unit which is expected to take approximately 40 days.

Port Reading Facility: The Corporation owns and operates a fluid catalytic cracking facility in Port Reading, New Jersey, with a capacity of 70,000 barrels per day. This facility, which processes residual fuel oil and vacuum gas oil, operated at a rate of approximately 63,000 barrels per day in 2009 compared with 64,000 barrels per day in 2008 and 61,000 barrels per day in 2007. Substantially all of Port Reading’s production is gasoline and heating oil. The Corporation is planning a turnaround for the Port Reading refining facility in the second quarter of 2010, which is expected to take approximately 35 days.

Marketing

The Corporation markets refined petroleum products, natural gas and electricity on the East Coast of the United States to the motoring public, wholesale distributors, industrial and commercial users, other petroleum companies, governmental agencies and public utilities.

The Corporation had 1,357 HESS^® gasoline stations at December 31, 2009, including stations owned by its WilcoHess joint venture (Hess 44%). Approximately 92% of the gasoline stations are operated by the Corporation or WilcoHess. Of the operated stations, 94% have convenience stores on the sites. Most of the Corporation’s gasoline stations are in New York, New Jersey, Pennsylvania, Florida, Massachusetts, North Carolina and South Carolina.

The table below summarizes marketing sales volumes:

Refined Product sales (thousands of barrels per day)

Gasoline

Distillates

Residuals

Total refined product sales

Natural gas (thousands of mcf per day)

Electricity (megawatts round the clock)

The Corporation owns 20 terminals with an aggregate storage capacity of 22 million barrels in its East Coast marketing areas. The Corporation also owns a terminal in St. Lucia with a storage capacity of 9 million barrels, which is operated for third party storage.

The Corporation has a 50% interest in Bayonne Energy Center, LLC, a joint venture that plans to build a natural gas fired electric generating station on property owned by Hess in Bayonne, New Jersey. The joint venture will sell electricity into the New York City market by a direct connection with the Con Edison Gowanus substation. Construction of the facility is scheduled to begin in mid-2010 and operations are to commence in late 2011.

The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and derivatives. The Corporation also takes energy commodity and derivative trading positions for its own account.

Majority-owned subsidiaries of the Corporation are pursuing investments in liquified natural gas regasification terminals and related supply, trading and marketing opportunities. Necessary regulatory approvals are being pursued for terminal projects on owned properties located in Fall River, Massachusetts, and Shannon, Ireland. In 2009 the Corporation leased property, with an option to purchase, in Logan Township, New Jersey for potential regasification facilities. In addition, a subsidiary of the Corporation is exploring the development of fuel cell technology.

For additional financial information by segment see Note 16, Segment Information in the notes to the financial statements.

Competition and Market Conditions

See Item 1A, Risk Factors Related to Our Business and Operations, for a discussion of competition and market conditions.

Other Items

Compliance with various existing environmental and pollution control regulations imposed by federal, state, local and foreign governments is not expected to have a material adverse effect on the Corporation’s financial condition or

results of operations. The Corporation anticipates capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, of approximately $50 million in 2010. For further discussion of environmental matters see the Environment, Health and Safety section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The number of persons employed by the Corporation at year end was approximately 13,300 in 2009 and 13,500 in 2008.

The Corporation’s Internet address is www.hess.com. On its website, the Corporation makes available free of charge its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after the Corporation electronically files with or furnishes such material to the Securities and Exchange Commission. Copies of the Corporation’s Code of Business Conduct and Ethics, its Corporate Governance Guidelines and the charters of the Audit Committee, the Compensation and Management Development Committee and the Corporate Governance and Nominating Committee of the Board of Directors are available on the Corporation’s website and are also available free of charge upon request to the Secretary of the Corporation at its principal executive offices. The Corporation has also filed with the New York Stock Exchange (NYSE) its annual certification that the Corporation’s chief executive officer is unaware of any violation of the NYSE’s corporate governance standards.

Our business activities and the value of our securities are subject to significant risk factors, including those described below. The risk factors described below could negatively affect our operations, financial condition, liquidity and results of operations, and as a result, holders and purchasers of our securities could lose part or all of their investments. It is possible additional risks relating to our securities may be described in a prospectus supplement if we issue securities in the future.

Commodity Price Risk: Our estimated proved reserves, revenue, operating cash flows, operating margins, future earnings and trading operations are highly dependent on the prices of crude oil, natural gas and refined petroleum products, which are influenced by numerous factors beyond our control. Historically these prices have been very volatile and most recently have been affected by changes in demand associated with the global economic downturn. The major foreign oil producing countries, including members of the Organization of Petroleum Exporting Countries (OPEC), exert considerable influence over the supply and price of crude oil and refined petroleum products. Their ability or inability to agree on a common policy on rates of production and other matters has a significant impact on the oil markets. The commodities trading markets may also influence the selling prices of crude oil, natural gas and refined petroleum products. To the extent that we engage in hedging activities to mitigate commodity price volatility, we may not realize the benefit of price increases above the hedged price. Changes in commodity prices can also have a material impact on collateral and margin requirements under our derivative contracts. In addition, we utilize significant bank credit facilities to support these collateral and margin requirements. An inability to renew or replace such credit facilities as they mature would negatively impact our liquidity.

Technical Risk: We own or have access to a finite amount of oil and gas reserves which will be depleted over time. Replacement of oil and gas reserves is subject to successful exploration drilling, development activities, and enhanced recovery programs. Therefore, future oil and gas production is dependent on technical success in finding and developing additional hydrocarbon reserves. Exploration activity involves the interpretation of seismic and other geological and geophysical data, which does not always successfully predict the presence of commercial quantities of hydrocarbons. Drilling risks include unexpected adverse conditions, irregularities in pressure or formations, equipment failure, blowouts and weather interruptions. Future developments may be affected by unforeseen reservoir conditions which negatively affect recovery factors or flow rates. The costs of drilling and development activities have increased in recent years which could negatively affect expected economic returns. Reserve replacement can also be achieved through acquisition. Although due diligence is used in evaluating acquired oil and gas properties, similar risks may be encountered in the production of oil and gas on properties acquired from others.

Oil and Gas Reserves and Discounted Future Net Cash Flow Risks: Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues from those reserves. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities and future net revenues of our proved reserves. In addition, reserve estimates may be subject to downward or upward revisions based on production performance, purchases or sales of properties, results of future development, prevailing oil and gas prices, production sharing contracts, which may decrease reserves as crude oil and natural gas prices increase, and other factors.

Political Risk: Federal, state, local, territorial and foreign laws and regulations relating to tax increases and retroactive tax claims, expropriation or nationalization of property, mandatory government participation, cancellation or amendment of contract rights, and changes in import regulations, limitations on access to exploration and development opportunities, as well as other political developments may affect our operations. Some of the international areas in which we operate and the partners with whom we operate, are politically less stable than other areas and partners. The threat of terrorism around the world also poses additional risks to the operations of the oil and gas industry. We market motor fuels through lessee-dealers and wholesalers in certain states where legislation prohibits producers or refiners of crude oil from directly engaging in retail marketing of motor fuels. Similar legislation has been periodically proposed in various other states.

Environmental Risk: Our oil and gas operations, like those of the industry, are subject to environmental risk such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for pollution or other environmental damage. Our operations are also subject to numerous United States federal, state, local and foreign environmental laws and regulations. Non-compliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial clean-ups and natural resource damages or other liabilities. In addition, increasingly stringent environmental regulations, particularly relating to the production of motor and other fuels have resulted and will likely continue to result in higher capital expenditures and operating expenses for us and the oil and gas industry in general.

Climate Change Risk: We recognize that climate change is a global environmental concern. Continuing political and social attention to the issue of climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit greenhouse gas emissions. These agreements and measures may require significant equipment modifications, operational changes, taxes, or purchase of emission credits to reduce emission of greenhouse gases from our operations, as a result of which we may incur substantial capital expenditures and compliance, operating, maintenance and remediation costs. In addition, we manufacture petroleum fuels, which through normal customer use result in the emission of greenhouse gases. Regulatory initiatives to reduce the use of these fuels may reduce our sales of, and revenues from, these products. Finally, to the extent that climate change may result in more extreme weather related events, we could experience increased costs related to prevention, maintenance and remediation of affected operations in addition to costs and lost revenues related to delays and shutdowns.

Competitive Risk: The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies in each of our activities, including acquiring rights to explore for crude oil and natural gas, and in purchasing and marketing of refined products, natural gas and electricity. Many competitors, including national oil companies, are larger and have substantially greater resources. We are also in competition with producers and marketers of other forms of energy. Increased competition for worldwide oil and gas assets has significantly increased the cost of acquisitions. In addition, competition for drilling services, technical expertise and equipment has, in the recent past, affected the availability of technical personnel and drilling rigs and has therefore increased capital and operating costs.

Catastrophic Risk: Although we maintain a level of insurance coverage consistent with industry practices against property and casualty losses, our oil and gas operations are subject to unforeseen occurrences which may damage or destroy assets or interrupt operations. Examples of catastrophic risks include hurricanes, fires, explosions and blowouts. These occurrences have affected us from time to time.

The Corporation, along with many other companies engaged in refining and marketing of gasoline, has been a party to lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline. A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the United States against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including the Corporation. The principal allegation in all cases is that gasoline containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. In 2008, the majority of the cases against the Corporation were settled. In February 2010, the Corporation reached an agreement in principle to settle all but three of the remaining cases. The three unresolved cases consist of two cases that have been consolidated for pre-trial purposes in the Southern District of New York as part of a multi-district litigation proceeding and an action brought in state court by the State of New Hampshire. In 2007, a pre-tax charge of $40 million was recorded to cover all of the known MTBE cases against the Corporation.

Over the last several years, many refiners have entered into consent agreements to resolve the United States Environmental Protection Agency’s (EPA) assertions that refining facilities were modified or expanded without complying with New Source Review regulations that require permits and new emission controls in certain circumstances and other regulations that impose emissions control requirements. These consent agreements, which arise out of an EPA enforcement initiative focusing on petroleum refiners and utilities, have typically imposed substantial civil fines and penalties and required (i) significant capital expenditures to install emissions control equipment over a three to eight year time period and (ii) changes to operations which resulted in increased operating costs. The capital expenditures, penalties and supplemental environmental projects for individual refineries covered by the settlements can vary significantly, depending on the size and configuration of the refinery, the circumstances of the alleged modifications and whether the refinery has previously installed more advanced pollution controls. The EPA initially contacted the Corporation and HOVENSA regarding the Petroleum Refinery Initiative in August 2003. Negotiations with the EPA and the relevant states and the Virgin Islands are continuing and substantial progress has been made toward resolving this matter for both the Corporation and HOVENSA. While the effect on the Corporation of the Petroleum Refining Initiative cannot be estimated until a final settlement is reached and entered by a court, additional significant future capital expenditures and operating expenses will likely be incurred by HOVENSA over a number of years. The amount of penalties, if any, is not expected to be material.

On September 13, 2007, HOVENSA received a Notice Of Violation (NOV) pursuant to section 113(a)(i) of the Clean Air Act (Act) from the EPA finding that HOVENSA failed to obtain proper permitting for the construction and operation of its delayed coking unit in accordance with applicable law and regulations. HOVENSA believes it properly obtained all necessary permits for this project. The NOV states that the EPA has authority to issue an administrative order assessing penalties for violation of the Act. HOVENSA has entered into discussions with the EPA to reach resolution of this matter. The Corporation does not believe that this matter will result in material liability to HOVENSA or the Corporation.

In December 2006, HOVENSA received a NOV from the EPA alleging non-compliance with emissions limits in a permit issued by the Virgin Islands Department of Planning and Natural Resources (DPNR) for the two process heaters in the delayed coking unit. The NOV was issued in response to a voluntary investigation and submission by HOVENSA regarding potential non-compliance with the permit emissions limits for two pollutants. Any exceedances were minor from the perspective of the amount of pollutants emitted in excess of the limits. HOVENSA has entered into discussions with the appropriate governmental agencies to reach resolution of this matter and does not believe that it will result in material liability to HOVENSA or the Corporation.

The Corporation received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the lower Passaic River and NJDEP is also seeking natural resource damages. The directive, insofar as it affects the Corporation, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey now owned by the Corporation. The Corporation and over 70 companies entered into an Administrative Order on Consent with the EPA to study the same contamination. NJDEP has also sued several other companies linked to a facility considered by the State to be the largest contributor to river

contamination. In January 2009, these companies added third party defendants, including the Corporation, to that case. In June 2007, the EPA issued a draft study which evaluated six alternatives for early action, with costs ranging from $900 million to $2.3 billion. Based on adverse comments from the Corporation and others, the EPA is reevaluating its alternatives. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given the ongoing studies, remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, the Corporation does not believe that this matter will result in material liability because its terminal could not have contributed contamination along most of the river’s length and did not store or use contaminants which are of the greatest concern in the river sediments, and because there are numerous other parties who will likely share in the cost of remediation and damages.

In July 2004, Hess Oil Virgin Islands Corp. (HOVIC), a wholly owned subsidiary of the Corporation, and HOVENSA, each received a letter from the Commissioner of the Virgin Islands Department of Planning and Natural Resources and Natural Resources Trustees, advising of the Trustee’s intention to bring suit against HOVIC and HOVENSA under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The letter alleges that HOVIC and HOVENSA are potentially responsible for damages to natural resources arising from releases of hazardous substances from the “HOVENSA Oil Refinery.” HOVENSA currently owns and operates a petroleum refinery on the south shore of St. Croix, United States Virgin Islands, which had been operated by HOVIC until October 1998. An action was filed on May 5, 2005 in the District Court of the Virgin Islands against HOVENSA, HOVIC and other companies that operated industrial facilities on the south shore of St. Croix asserting that the defendants are liable under CERCLA and territorial statutory and common law for damages to natural resources. HOVIC and HOVENSA do not believe that this matter will result in a material liability as they believe that they have strong defenses to this complaint, and they intend to vigorously defend this matter.

The Securities and Exchange Commission (SEC) notified the Corporation that on July 21, 2005 it commenced a private investigation into payments made to the government of Equatorial Guinea or to officials and persons affiliated with officials of the government of Equatorial Guinea. In 2009, the SEC advised that it had completed its investigation and did not intend to recommend enforcement action against the Corporation.

The Corporation periodically receives notices from EPA that it is a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties are jointly and severally liable. For certain sites, EPA’s claims or assertions of liability against the Corporation relating to these sites have not been fully developed. With respect to the remaining sites, EPA’s claims have been settled, or a proposed settlement is under consideration, in all cases for amounts that are not material. The ultimate impact of these proceedings, and of any related proceedings by private parties, on the business or accounts of the Corporation cannot be predicted at this time due to the large number of other potentially responsible parties and the speculative nature of clean-up cost estimates, but is not expected to be material.

The Corporation is from time to time involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. Although the ultimate outcome of these proceedings cannot be ascertained at this time and some of them may be resolved adversely to the Corporation, no such proceeding is required to be disclosed under applicable rules of the SEC. In management’s opinion, based upon currently known facts and circumstances, such proceedings in the aggregate will not have a material adverse effect on the financial condition of the Corporation.

During the fourth quarter of 2009, no matter was submitted to a vote of security holders through the solicitation of proxies or otherwise.

The following table presents information as of February 1, 2010 regarding executive officers of the Registrant:

Name

John B. Hess

Gregory P. Hill

F. Borden Walker

Timothy B. Goodell

Lawrence H. Ornstein

John P. Rielly

John J. Scelfo

Mykel J. Ziolo

Sachin J. Mehra

Except for Messrs. Hill, Goodell, and Mehra, each of the above officers has been employed by the Registrant or its subsidiaries in various managerial and executive capacities for more than five years. Prior to joining the Corporation, Mr. Hill served in senior executive positions in exploration and production operations at Royal Dutch Shell and its subsidiaries, where he was employed for 25 years. Before joining the Corporation in 2009, Mr. Goodell was a partner in the law firm of White & Case LLP. Mr. Mehra was employed in treasury and financial functions at General Motors before joining the Corporation in 2007.

Stock Market Information

The common stock of Hess Corporation is traded principally on the New York Stock Exchange (ticker symbol: HES). High and low sales prices were as follows:

Quarter Ended

March 31

June 30

September 30

December 31

Performance Graph

Set forth below is a line graph comparing the Corporation’s cumulative total shareholder return for five years, assuming reinvestment of dividends on common stock, with the cumulative total return of:

Comparison of Five-Year Shareholder Returns
Years Ended December 31,

Holders

At December 31, 2009, there were 5,926 stockholders (based on number of holders of record) who owned a total of 327,229,488 shares of common stock.

Dividends

Cash dividends on common stock totaled $0.40 per share ($0.10 per quarter) during 2009, 2008 and 2007.

Equity Compensation Plans

Following is information on the Registrant’s equity compensation plans at December 31, 2009:

Plan Category

Equity compensation plans approved by security holders

Equity compensation plans not approved by security holders**

See Note 8, Share-Based Compensation, in the notes to the financial statements for further discussion of the Corporation’s equity compensation plans.

A five-year summary of selected financial data follows*:

Sales and other operating revenues

Crude oil and natural gas liquids

Natural gas (including sales of purchased gas)

Refined petroleum products

Electricity

Convenience store sales and other operating revenues

Net income attributable to Hess Corporation

Less: preferred stock dividends

Net income applicable to Hess Corporation common shareholders

Earnings per share**

Basic

Diluted

Total assets

Total debt

Total equity

Dividends per share of common stock**

Overview

The Corporation is a global integrated energy company that operates in two segments, Exploration and Production (E&P) and Marketing and Refining (M&R). The E&P segment explores for, develops, produces, purchases, transports and sells crude oil and natural gas. The M&R segment manufactures refined petroleum products and purchases, markets and trades, refined petroleum products, natural gas and electricity.

Net income in 2009 was $740 million compared with $2,360 million in 2008 and $1,832 million in 2007. Diluted earnings per share were $2.27 in 2009 compared with $7.24 in 2008 and $5.74 in 2007. A table of items affecting comparability between periods is shown on page 20.

Exploration and Production

The Corporation’s strategy for the E&P segment is to profitably grow reserves and production in a sustainable and financially disciplined manner. The Corporation’s total proved reserves were 1,437 million barrels of oil equivalent (boe) at December 31, 2009 compared with 1,432 million boe at December 31, 2008 and 1,330 million boe at December 31, 2007. Total proved reserves additions for 2009 were 157 million boe. These additions replaced approximately 103% of the Corporation’s 2009 production.

E&P net income was $1,042 million in 2009, $2,423 million in 2008 and $1,842 million in 2007. Average realized crude oil selling prices were $51.62 per barrel in 2009, $82.04 in 2008, and $63.44 in 2007, including the impact of hedging. The variance in E&P earnings between years was primarily driven by the fluctuations in average realized crude oil selling prices.

Production averaged 408,000 barrels of oil equivalent per day (boepd) in 2009 compared with 381,000 boepd in 2008 and 377,000 boepd in 2007. Production in 2009 increased 27,000 boepd or 7% from 2008. In 2010, the Corporation currently estimates total worldwide production will average between 400,000 and 410,000 boepd.

The following is an update of significant E&P activities during 2009:

Marketing and Refining

The Corporation’s strategy for the M&R segment is to deliver consistent operating performance and generate free cash flow. M&R net income was $127 million in 2009, $277 million in 2008 and $300 million in 2007. The declining earnings were due to lower average margins, which include the effect of the global economic downturn that began in 2008 and continued into 2009. Refining operations contributed net income (loss) of $(87) million in 2009, $73 million in 2008 and $193 million in 2007. Marketing earnings were $168 million in 2009, $240 million in 2008 and $83 million in 2007.

Liquidity and Capital and Exploratory Expenditures

Net cash provided by operating activities was $3,046 million in 2009, $4,688 million in 2008 and $3,627 million in 2007, principally reflecting fluctuations in earnings. At December 31, 2009, cash and cash equivalents totaled $1,362 million compared with $908 million at December 31, 2008. Total debt was $4,467 million at December 31, 2009 compared with $3,955 million at December 31, 2008. In February 2009, the Corporation issued $250 million of 5 year senior unsecured notes with a coupon of 7% and $1 billion of 10 year senior unsecured notes with a coupon of 8.125%. The majority of the proceeds were used to repay debt under the revolving credit facility and outstanding borrowings on other credit facilities. In December 2009, the Corporation issued $750 million of 30 year bonds at a coupon of 6% and tendered for $662 million of bonds due in August 2011. The Corporation completed the repurchase of $546 million of the 2011 bonds in December 2009 and repurchased the remaining $116 million of these bonds in January 2010. The Corporation’s debt to capitalization ratio at December 31, 2009 was 24.8% compared with 24.2% at the end of 2008.

Capital and exploratory expenditures were as follows for the years ended December 31:

Exploration and Production

International

Total Exploration and Production

Marketing, Refining and Corporate

Total Capital and Exploratory Expenditures

Exploration expenses charged to income included above:

Total exploration expenses charged to income included above

The Corporation anticipates investing $4.1 billion in capital and exploratory expenditures in 2010, substantially all of which relates to E&P operations.

Consolidated Results of Operations

The after-tax results by major operating activity are summarized below:

Marketing and Refining

Corporate

Interest expense

Net income per share — diluted

The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income and affect comparability between periods. The items in the table below are explained on pages 23 through 25.

In the discussion that 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 review of variances in segment earnings. Management believes that after-tax amounts 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 income tax rate in each tax jurisdiction to pre-tax amounts.

Comparison of Results

Following is a summarized income statement of the Corporation’s E&P operations:

Sales and other operating revenues*

Other, net

Total revenues and non operating income

Costs and expenses

Production expenses, including related taxes

Exploration expenses, including dry holes and lease impairment

General, administrative and other expenses

Depreciation, depletion and amortization

Total costs and expenses

Results of operations before income taxes

Provision for income taxes

Results of operations attributable to Hess Corporation

After considering the E&P items in the table on page 23, the remaining changes in E&P earnings are primarily attributable to changes in selling prices, production volumes, operating costs, exploration expenses, foreign exchange, and income taxes, as discussed below.

Selling prices: Lower average selling prices reduced E&P revenues by approximately $4,000 million in 2009 compared with 2008. Higher average selling prices increased E&P revenues by approximately $2,100 million in 2008 compared with 2007.

The Corporation’s average selling prices were as follows:

Crude oil-per barrel (including hedging)

Worldwide

Crude oil-per barrel (excluding hedging)

Natural gas liquids-per barrel

Natural gas-per mcf (including hedging)

Natural gas-per mcf (excluding hedging)

In October 2008, the Corporation closed its Brent crude oil hedges, covering 24,000 barrels per day from 2009 though 2012, by entering into offsetting contracts with the same counterparty. The deferred after-tax loss as of the date the hedge positions were closed will be recorded in earnings as the contracts mature. The estimated annual after-tax loss from the closed positions will be approximately $335 million from 2010 through 2012. Crude oil hedges reduced E&P earnings by $337 million ($533 million before income taxes) in 2009. Crude oil and natural gas hedges reduced E&P earnings by $423 million ($685 million before income taxes) in 2008 and $244 million ($399 million before income taxes) in 2007.

Production and sales volumes: The Corporation’s crude oil and natural gas production was 408,000 boepd in 2009 compared with 381,000 boepd in 2008 and 377,000 boepd in 2007. The Corporation currently estimates that its 2010 production will average between 400,000 and 410,000 boepd.

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

Crude oil (barrels per day)

Natural gas liquids (barrels per day)

Natural gas (mcf per day)

Barrels of oil equivalent* (barrels per day)

United States: Crude oil and natural gas production in the United States was higher in 2009 compared with 2008, primarily due to new production from the Shenzi Field and production resuming after the 2008 hurricanes. Crude oil production was slightly higher in 2008 compared with 2007, principally due to production from new wells in North Dakota and the deepwater Gulf of Mexico, largely offset by the impact of hurricanes in the Gulf of Mexico. Natural gas production was lower in 2008 compared to 2007, primarily reflecting hurricane downtime and natural decline. Hurricane impacts reduced full year 2008 production by an estimated 7,000 boepd.

Europe: Crude oil production was comparable in 2009 and 2008, as higher production in Russia offset lower production in the United Kingdom North Sea. Crude oil production in 2008 was lower than in 2007, due to temporary shut-ins at three North Sea fields, the cessation of production at the Fife, Fergus, Flora and Angus fields, and natural decline. These decreases were partially offset by increased production in Russia. Natural gas production was lower in 2009 compared with 2008, primarily due to decline at the Atlantic and Cromarty fields.

Africa: Crude oil production decreased in 2009 compared with 2008 primarily due to lower production from the Ceiba Field. Crude oil production increased in 2008 compared with 2007, primarily due to higher production at the Okume Complex, partially offset by a lower entitlement to Algerian production.

Asia and other: Natural gas production in 2009 was higher than in 2008, primarily due to a full year of Phase 2 gas sales from the Joint Development Area of Malaysia/Thailand (JDA). Natural gas production increased in 2008 compared with 2007 due to increased production from Block A-18 in the JDA and a full year of production from the Ujung Pangkah Field in Indonesia. The decrease in crude oil production in 2008 from 2007 principally reflects changes to the Corporation’s entitlement to production in Azerbaijan.

Sales volumes: Higher sales volumes and other operating revenues increased revenue by approximately $1,030 million in 2009 compared with 2008 and $200 million in 2008 compared with 2007.

Operating costs and depreciation, depletion and amortization: Excluding the impact of items affecting comparability explained on page 23, cash operating costs, consisting of production expenses and general and administrative expenses, decreased by $119 million in 2009 and increased by $321 million in 2008 compared with the corresponding amounts in the prior years. The decrease in 2009 compared with 2008 was primarily due to lower

production taxes (due to lower realized selling prices), the cessation of production at several North Sea fields, the favorable impact of foreign exchange rates and cost savings initiatives, partially offset by the impact of higher production volumes. The increase in costs in 2008 compared to 2007 was primarily due to increased production taxes (due to higher realized selling prices), increased cost of services and materials and higher employee costs.

Excluding the impact of items affecting comparability, depreciation, depletion and amortization charges increased by $192 million in 2009 and $531 million in 2008, compared with the corresponding amounts in the prior years. The increases in 2009 and 2008 were primarily due to higher production volumes and per barrel costs, reflecting higher finding and development costs.

Excluding items affecting comparability between periods, unit costs were as follows. Cash operating costs per barrel of oil equivalent were $13.70 in 2009, $15.49 in 2008 and $13.36 in 2007. Cash operating costs in 2010 are estimated to be in the range of $15 to $16 per barrel of oil equivalent. Depreciation, depletion and amortization costs per barrel of oil equivalent were $14.19 in 2009, $13.79 in 2008 and $10.11 in 2007. Depreciation, depletion and amortization costs for 2010 are estimated to be in the range of $14.50 to $15.50 per barrel of oil equivalent.

Exploration expenses: Exploration expenses increased in 2009 from 2008, primarily due to higher dry hole costs and lease amortization, partially offset by lower geological and seismic expense. Exploration expenses increased in 2008 compared to 2007, mainly due to higher dry hole costs.

Income taxes: Excluding the impact of items affecting comparability, the effective income tax rates for E&P operations were 48% in 2009, 49% in 2008 and 50% in 2007. The effective income tax rate for E&P operations in 2010 is estimated to be in the range of 47% to 51%.

Foreign Exchange: The after-tax foreign currency losses were $10 million in 2009, $80 million in 2008 and $7 million in 2007. The foreign currency loss in 2008 reflects the net effect of significant exchange rate movements in the fourth quarter of 2008 on the remeasurement of assets, liabilities and foreign currency forward contracts by certain foreign businesses.

Reported E&P earnings include the following items affecting comparability of income (expense) before and after income taxes:

Royalty dispute resolution

Gains from asset sales

Reductions in carrying values of assets

Hurricane related costs

Estimated production imbalance settlements

2009: In October 2009, the U.S. Supreme Court decided it would not review the decision of the 5th Circuit Court of Appeals against the U.S. Minerals Management Service relating to royalty relief under the Deep Water Royalty Relief Act of 1995. As a result, the Corporation recognized an after-tax gain of $89 million to reverse all previously recorded royalties covering the periods from 2003 to 2009. The pre-tax gain of $143 million is reported in Other, net within the Statement of Consolidated Income.

After-tax charges of $44 million ($77 million before income taxes) were recorded to impair the carrying values of production equipment and two short-lived fields in the United Kingdom North Sea, and to write down materials inventories in Equatorial Guinea and the United States. The pre-tax amount of the impairment charges totaling $52 million were reported in Depreciation, depletion and amortization and the majority of the $25 million in inventory write downs was reported in Production expenses in the Statement of Consolidated Income.

2008: The charge for asset impairments relates to mature fields in the United States and the United Kingdom North Sea. The hurricane costs relate to expenses associated with Hurricanes Gustav and Ike in the Gulf of Mexico and are recorded in Production expenses.

2007: The gain from asset sales relates to the sale of the Corporation’s interests in the Scott and Telford fields in the United Kingdom North Sea. The charge for asset impairments relates to two mature fields also in the United Kingdom North Sea. The estimated production imbalance settlements represent a charge for adjustments to prior meter readings at two offshore fields, which are recorded as a reduction of Sales and other operating revenues.

The Corporation’s future E&P earnings may be impacted by external factors, such as volatility in the selling prices of crude oil and natural gas, reserve and production changes, political risk, industry costs, exploration expenses, the effects of weather and changes in foreign exchange and income tax rates.

Earnings from M&R activities amounted to $127 million in 2009, $277 million in 2008 and $300 million in 2007. Excluding the items affecting comparability reflected in the table on page 20 and discussed below, the earnings were $115 million, $277 million and $276 million, respectively.

Refining: Refining earnings (losses), which consist of the Corporation’s share of HOVENSA’s results, Port Reading earnings, interest income on a note receivable from PDVSA and results of other miscellaneous operating activities, were $(87) million in 2009 (including a benefit of $12 million due to an income tax adjustment), $73 million in 2008, and $193 million in 2007.

The Corporation’s share of HOVENSA’s results was a loss of $141 million ($229 million before income taxes) in 2009, and income of $27 million ($44 million before income taxes) in 2008 and $108 million ($176 million before income taxes) in 2007. The declining earnings were principally due to lower refining margins. The 2009 and 2008 utilization rates for HOVENSA reflect weaker refining margins and planned and unplanned maintenance. The 2008 utilization rates also reflect a refinery wide shut down for Hurricane Omar. In 2007, the coker unit at HOVENSA was shutdown for approximately 30 days for a scheduled turnaround. Certain related processing units were also included in this turnaround. In January 2010, HOVENSA commenced a turnaround of its FCC unit which is expected to take approximately 40 days. The Corporation’s estimated share of HOVENSA’s turnaround expenses after income taxes is expected to be approximately $20 million.

Cash distributions received by the Corporation from HOVENSA were $50 million in 2008 and $300 million in 2007. In 2009, the remaining balance on the note issued by PDVSA at inception of the joint venture was fully repaid.

Other after-tax refining earnings, principally from Port Reading operations, were $43 million in both 2009 and 2008 and $79 million in 2007, reflecting lower margins. The Corporation is planning a turnaround for the Port Reading refining facility in the second quarter of 2010, which is expected to take approximately 35 days. The estimated after-tax expenses for the Port Reading turnaround are approximately $25 million.

The following table summarizes refinery utilization rates:

HOVENSA

Crude

Fluid catalytic cracker

Coker

Port Reading

Marketing: Marketing operations, which consist principally of retail gasoline and energy marketing activities, generated income of $168 million in 2009, $240 million in 2008 and $83 million in 2007, including income from the liquidation of LIFO inventories in 2007 totaling $24 million ($38 million before income taxes).

The decrease in earnings in 2009 compared with 2008 reflects lower margins in a weak economic environment. The increase in 2008 compared with 2007 primarily reflects higher margins on refined product sales, including sales of retail gasoline operations.

Refined product sales (thousands of barrels per day)

The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and energy derivatives. The Corporation also takes trading positions for its own account. The Corporation’s after-tax results from trading activities, including its share of the results of the trading partnership, amounted to earnings of $46 million in 2009, a loss of $36 million in 2008 and earnings of $24 million in 2007.

Marketing expenses decreased in 2009 as compared with 2008, principally reflecting lower retail credit card fees. Marketing expenses increased in 2008 compared with 2007, due to growth in energy marketing activities, higher retail credit card fees, and increased transportation costs.

The Corporation’s future M&R earnings may be impacted by external factors, such as volatility in margins, competitive industry conditions, government regulations, credit risk, and supply and demand factors, including the effects of weather.

Corporate

The following table summarizes corporate expenses:

Corporate expenses

Income taxes (benefits)

After-tax corporate expenses

Items affecting comparability between periods, after tax

Net corporate expenses

Excluding items affecting comparability between periods, the decrease in corporate expenses in 2009 compared with 2008 primarily reflects gains on supplemental pension related investments, together with lower employee and professional costs, partly offset by higher bank facility fees. The increase in corporate expenses in 2008 compared with 2007 primarily reflects losses on supplemental pension related investments and higher employee and professional costs. After-tax corporate expenses in 2010 are estimated to be in the range of $160 to $170 million.

In 2009, the Corporation recorded after-tax charges of $34 million ($54 million before income taxes) related to the repurchase of $546 million in notes that were scheduled to mature in 2011 and $26 million ($42 million before income taxes) relating to retirement benefits and employee severance costs. The pre-tax charge in connection with the debt repurchase was recorded in Other, net, and the pre-tax amount of the retirement benefits and severance costs was recorded in General and administrative expenses within the Statement of Consolidated Income. In 2007, Corporate expenses included a charge of $25 million ($40 million before income taxes) related to MTBE litigation. The pre-tax amount of this charge was recorded in General and administrative expenses.

Interest

Interest expense was as follows:

Total interest incurred

Less capitalized interest

Interest expense before income taxes

Less income taxes

After-tax interest expense

The increase in interest expense primarily reflects higher debt and fees for letters of credit. The decrease in capitalized interest in 2009 and 2008 compared to 2007 reflects the completion of several development projects in 2007. After-tax interest expense in 2010 is expected to be in the range of $220 to $230 million.

Sales and Other Operating Revenues

Sales and other operating revenues totaled $29,614 million in 2009, a decrease of 28% compared with 2008. In 2008, sales and other operating revenues totaled $41,134 million, an increase of 30% compared with 2007. The fluctuations in each year primarily reflect changes in crude oil and refined product selling prices.

The change in cost of goods sold in each year principally reflects the change in sales volumes and prices of refined products and purchased natural gas and electricity.

Liquidity and Capital Resources

The following table sets forth certain relevant measures of the Corporation’s liquidity and capital resources as of December 31:

Cash and cash equivalents

Current portion of long-term debt

Debt to capitalization ratio*

Cash Flows

The following table sets forth a summary of the Corporation’s cash flows:

Net cash provided by (used in):

Operating activities

Investing activities

Financing activities

Net increase in cash and cash equivalents

Operating Activities: Net cash provided by operating activities, including changes in operating assets and liabilities, was $3,046 million in 2009 compared with $4,688 million in 2008, reflecting lower earnings. Operating

cash flow increased to $4,688 million in 2008 from $3,627 million in 2007, primarily reflecting increased earnings. The Corporation received cash distributions from HOVENSA of $50 million in 2008 and $300 million in 2007.

Investing Activities: The following table summarizes the Corporation’s capital expenditures:

Exploration

Production and development

Acquisitions (including leaseholds)

Capital expenditures in 2009 include acquisitions of $188 million for unproved leaseholds and $74 million for a 50% interest in blocks PM301 and PM302 in Malaysia, which are adjacent to Block A-18 of the JDA. Capital expenditures in 2008 include $600 million for leasehold acquisitions in the United States and $210 million for the acquisition of the remaining 22.5% interest in the Corporation’s Gabonese subsidiary. In 2008, the Corporation also selectively expanded its energy marketing business by acquiring fuel oil, natural gas, and electricity customer accounts, and a terminal and related assets, for an aggregate of approximately $100 million. In 2007, capital expenditures include the acquisition of a 28% interest in the Genghis Khan Field in the deepwater Gulf of Mexico for $371 million.

In 2007, the Corporation received proceeds of $93 million for the sale of its interests in the Scott and Telford fields located in the United Kingdom.

Financing Activities: During 2009, net proceeds from borrowings were $447 million. In February 2009, the Corporation issued $250 million of 5 year senior unsecured notes with a coupon of 7% and $1 billion of 10 year senior unsecured notes with a coupon of 8.125%. The majority of the proceeds were used to repay debt under the revolving credit facility and outstanding borrowings on other credit facilities. In December 2009, the Corporation issued $750 million of 30 year bonds with a coupon of 6% and tendered for the $662 million of bonds due in August 2011. The Corporation completed the repurchase of $546 million of the 2011 bonds in December 2009. The remaining $116 million of 2011 bonds, classified as Current maturities of long term debt at December 31, 2009, was redeemed in January 2010, resulting in a charge of approximately $11 million ($7 million after income taxes). During 2008, net repayments of debt were $32 million, compared with net borrowings of $208 million in 2007.

Total common stock dividends paid were $131 million, $130 million and $127 million in 2009, 2008 and 2007, respectively. The Corporation received net proceeds from the exercise of stock options, including related income tax benefits, of $18 million, $340 million and $111 million in 2009, 2008 and 2007, respectively.

Future Capital Requirements and Resources

The Corporation anticipates investing a total of approximately $4.1 billion in capital and exploratory expenditures during 2010, substantially all of which is targeted for E&P operations. In the Corporation’s M&R operations, refining margins are currently weak, which have adversely affected HOVENSA’s liquidity position. The Corporation intends to provide its share of any necessary financial support for HOVENSA. The Corporation expects to fund its 2010 operations, including capital expenditures, dividends, pension contributions and required debt repayments and any necessary financial support for HOVENSA, with existing cash on-hand, cash flow from operations and its available credit facilities. Crude oil prices, natural gas prices and refining margins are volatile and difficult to predict. In addition, unplanned increases in the Corporation’s capital expenditure program could occur. If conditions were to change, such as a significant decrease in commodity prices or an unexpected increase in capital expenditures, the Corporation would take steps to protect its financial flexibility and may pursue other sources of liquidity, including the issuance of debt securities, the issuance of equity securities, and/or asset sales.

The table below summarizes the capacity, usage, and available capacity of the Corporation’s borrowing and letter of credit facilities at December 31, 2009 (in millions):

Revolving credit facility

Asset backed credit facility

Committed lines

Uncommitted lines

The Corporation maintains a $3.0 billion syndicated, revolving credit facility (the facility), of which $2,925 million is committed through May 2012. The facility can be used for borrowings and letters of credit. At December 31, 2009, available capacity under the facility was $3.0 billion. The Corporation has a 364 day asset-backed credit facility securitized by certain accounts receivable from its M&R operations. At December 31, 2009, under the terms of this financing arrangement, the Corporation has the ability to borrow or issue letters of credit of up to $1.0 billion, subject to the availability of sufficient levels of eligible receivables. At December 31, 2009, outstanding letters of credit under this facility were collateralized by a total of $1,326 million of accounts receivable, which are held by a wholly owned subsidiary. These receivables are only available to pay the general obligations of the Corporation after satisfaction of the outstanding obligations under the asset backed facility.

The Corporation also has a shelf registration under which it may issue additional debt securities, warrants, common stock or preferred stock.

A loan agreement covenant based on the Corporation’s debt to capitalization ratio allows the Corporation to borrow up to an additional $18.1 billion for the construction or acquisition of assets at December 31, 2009. The Corporation has the ability to borrow up to an additional $3.7 billion of secured debt at December 31, 2009 under the loan agreement covenants.

The Corporation’s $2,847 million in letters of credit outstanding at December 31, 2009 were primarily issued to satisfy margin requirements. See also Note 14, Risk Management and Trading Activities.

Credit Ratings

There are three major credit rating agencies that rate the Corporation’s debt. All three agencies have currently assigned an investment grade rating to the Corporation’s debt. The interest rates and facility fees charged on some of the Corporation’s credit facilities, as well as margin requirements from risk management and trading counterparties, are subject to adjustment if the Corporation’s credit rating changes.

Contractual Obligations and Contingencies

Following is a table showing aggregated information about certain contractual obligations at December 31, 2009:

Long-term debt*

Operating leases

Purchase obligations

Supply commitments**

Capital expenditures

Operating expenses

Other long-term liabilities

In the preceding table, the Corporation’s supply commitments include its estimated purchases of 50% of HOVENSA’s production of refined products, after anticipated sales by HOVENSA to unaffiliated parties. The value of future supply commitments will fluctuate based on prevailing market prices at the time of purchase, the actual output from HOVENSA, and the level of sales to unaffiliated parties. Also included are term purchase agreements at market prices for additional gasoline necessary to supply the Corporation’s retail marketing system and feedstocks for the Port Reading refining facility. In addition, the Corporation has commitments to purchase refined products, natural gas and electricity to supply contracted customers in its energy marketing business. These commitments were computed based predominately on year-end market prices.

The table also reflects future capital expenditures, including the portion of the Corporation’s planned $4.1 billion capital investment program for 2010 that is contractually committed at December 31, 2009. Obligations for operating expenses include commitments for transportation, seismic purchases, oil and gas production expenses and other normal business expenses. Other long-term liabilities reflect contractually committed obligations on the balance sheet at December 31, 2009, including asset retirement obligations, pension plan liabilities and anticipated obligations for uncertain income tax positions.

The Corporation and certain of its subsidiaries lease gasoline stations, drilling rigs, tankers, office space and other assets for varying periods under leases accounted for as operating leases. The Corporation entered into a lease agreement for a new drillship and related support services for use in its global deepwater exploration and development activities. The total payments under this five year contract are expected to be approximately $950 million. The Corporation took delivery of the drillship in the fourth quarter of 2009.

The Corporation has a contingent purchase obligation, expiring in April 2012, to acquire the remaining interest in WilcoHess, a retail gasoline station joint venture, for approximately $184 million as of December 31, 2009.

The Corporation guarantees the payment of up to 50% of HOVENSA’s crude oil purchases from certain 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 December 31, 2009 it amounted to $121 million. In addition, the Corporation has agreed to provide funding up to a maximum of $15 million to the extent HOVENSA does not have funds to meet its senior debt obligations.

The Corporation is contingently liable under letters of credit and under guarantees of the debt of other entities directly related to its business at December 31, 2009 as shown below:

Letters of credit

Guarantees

Off-Balance Sheet Arrangements

The Corporation has leveraged leases not included in its balance sheet, primarily related to retail gasoline stations that the Corporation operates. The net present value of these leases is $412 million at December 31, 2009 compared with $491 million at December 31, 2008. The Corporation’s December 31, 2009 debt to capitalization ratio would increase from 24.8% to 26.5% if these leases were included as debt.

See also Note 4, Refining Joint Venture, and Note 15, Guarantees and Contingencies, in the notes to the financial statements.

Foreign Operations

The Corporation conducts exploration and production activities outside the United States, principally in Algeria, Australia, Azerbaijan, Brazil, Colombia, Denmark, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia, Libya, Malaysia, Norway, Peru, Russia, Thailand, and the United Kingdom. Therefore, the Corporation is subject to the risks associated with foreign operations, including political risk, tax law changes, and currency risk.

See also Item 1A. Risk Factors Related to Our Business and Operations.

Accounting Policies

Critical Accounting Policies and Estimates

Accounting policies and estimates 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, equity and various financial statement ratios. However, the Corporation’s accounting policies generally do not change cash flows or liquidity.

Accounting for Exploration and Development Costs: Exploration and production activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.

The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.

Crude Oil and Natural Gas Reserves: The SEC revised its oil and gas reserve estimation and disclosure requirements effective for year-end 2009 reporting. In addition, the Financial Accounting Standards Board (FASB) revised its accounting standard on oil and gas reserve estimation and disclosures. The determination of estimated

proved reserves is a significant element in arriving at the results of operations of exploration and production activities. The estimates of proved reserves affect well capitalizations, the unit of production depreciation rates of proved properties and wells and equipment, as well as impairment testing of oil and gas assets and goodwill.

For reserves to be booked as proved they must be determined with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. In addition, government and project operator approvals must be obtained and, depending on the amount of the project cost, senior management or the board of directors must commit to fund the project. The Corporation maintains its own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties. The Corporation’s technical staff updates reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management review. The Corporation also engaged an independent third party consulting firm to audit approximately 80% of the Corporation’s total proved reserves.

Impairment of Long-Lived Assets and Goodwill: 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 based on identifiable cash flows that 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 flow estimates, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets generally 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 and discounted at a risk-adjusted rate. 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 historical twelve month average prices.

The Corporation’s impairment tests of long-lived E&P producing assets are based on its best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each time an impairment test is performed. The Corporation could have impairments if the projected production volumes from oil and gas fields decrease, crude oil and natural gas selling prices decline significantly for an extended period or future estimated capital and operating costs increase significantly.

The Corporation’s goodwill is tested for impairment at a reporting unit level, which is an operating segment or one level below an operating segment. The impairment test is conducted annually in the fourth quarter or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable. 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. The Corporation’s goodwill is assigned to the E&P operating segment and it expects that the benefits of goodwill will be recovered through the operation of that segment.

The Corporation’s fair value estimate of the E&P segment is the sum of: (1) the discounted anticipated cash flows of producing assets and known developments, (2) the estimated risk adjusted 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 E&P segment depends on estimates about oil and gas reserves, future prices, timing of future net cash flows and market premiums. Significant extended declines in crude oil and natural gas prices or reduced reserve estimates could lead to a decrease in the fair value of the E&P segment that could result in an impairment of goodwill.

As there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing, there may be impairments of individual assets that would not cause an impairment of the goodwill assigned to the E&P segment.

Income Taxes: Judgments are required in the determination and recognition of income tax assets and liabilities in the financial statements. These judgments include the requirement to only recognize the financial statement effect of a tax position when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination.

The Corporation has net operating loss carryforwards or credit carryforwards in several jurisdictions, including the United States, and has recorded deferred tax assets for those losses and credits. Additionally, the Corporation has deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized. In evaluating realizability of deferred tax assets, the Corporation refers to the reversal periods for temporary differences, available carryforward periods for net operating losses and credit carryforwards, estimates of future taxable income, the availability of tax planning strategies, the existence of appreciated assets and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves and selling prices that are consistent with the Corporation’s internal business forecasts. Additionally, the Corporation has income taxes which have been deferred on intercompany transactions eliminated in consolidation related to transfers of property, plant and equipment remaining within the consolidated group. The amortization of these income taxes deferred on intercompany transactions will occur ratably with the recovery through depletion and depreciation of the carrying value of these assets. The Corporation does not provide for deferred U.S. income taxes for that portion of undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations.

Fair Value Measurements: The Corporation’s derivative instruments and supplemental pension plan investments are recorded at fair value, with changes in fair value recognized in earnings or other comprehensive income each period. The Corporation uses various valuation approaches in determining fair value, including the market and income approaches. The Corporation’s fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and the Corporation’s credit is considered for accrued liabilities.

The Corporation determines fair value in accordance with the FASB fair value measurements accounting standard which established a hierarchy that categorizes the sources of inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Multiple inputs may be used to measure fair value, however, the level of fair value is based on the lowest significant input level within this fair value hierarchy. Inputs include discounted cash flow calculations and other unobservable data.

The Corporation also records certain nonfinancial assets and liabilities at fair value. These fair value measurements include assets and liabilities recorded in connection with business combinations, the initial recognition of asset retirement obligations and long-lived assets and goodwill measured at fair value in an impairment assessment.

Details on the methods and assumptions used to determine the fair values are as follows:

Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. The fair value of certain of the Corporation’s exchange traded futures and options are considered Level 1.

Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange traded curve but have contractual terms that are not identical to exchange traded contracts. The Corporation utilizes fair value measurements based on Level 2 inputs for certain forwards, swaps and options. The liability related to the Corporation’s crude oil hedges is classified as Level 2.

Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data determined from sources with little or no market activity for comparable contracts or are positions with longer durations. For example, in its energy marketing business, the Corporation sells natural gas and electricity to customers and offsets the price exposure by purchasing forward contracts. The fair value of these sales and purchases may be based on specific prices at less liquid delivered locations, which are classified as Level 3. Fair values determined using discounted cash flows are also classified as Level 3.

Derivatives: The Corporation utilizes derivative instruments for both risk management and trading activities. In risk management activities, the Corporation uses futures, forwards, options and swaps, individually or in combination to mitigate its exposure to fluctuations in the prices of crude oil, natural gas, refined products and electricity, as well as changes in interest and foreign currency exchange rates. In trading activities, the Corporation, principally through a consolidated partnership, trades energy commodities and derivatives, including futures, forwards, options and swaps, based on expectations of future market conditions.

All derivative instruments are recorded at fair value in the Corporation’s balance sheet. The Corporation’s policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges) or hedges of firm commitments (fair value hedges). The effective portion of changes in fair value of derivatives that are designated as cash flow hedges is recorded as a component of other comprehensive income (loss). Amounts included in accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of derivatives designated as cash flow hedges is recorded currently in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.

Derivatives that are designated as either cash flow or fair value hedges are tested for effectiveness prospectively before they are executed and both prospectively and retrospectively on an on-going basis to determine whether they continue to qualify for hedge accounting. The prospective and retrospective effectiveness calculations are performed using either historical simulation or other statistical models, which utilize historical observable market data consisting of futures curves and spot prices.

Retirement Plans: The Corporation has funded non-contributory defined benefit pension plans and an unfunded supplemental pension plan. The Corporation recognizes on the balance sheet the net change in the funded status of the projected benefit obligation for these plans.

The determination of the obligations and expenses related to these plans are based on several actuarial assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; and rate of future increases in compensation levels. These assumptions represent estimates made by the Corporation, some of which can be affected by external factors. For example, the discount rate used to estimate the Corporation’s projected benefit obligation is based on a portfolio of high-quality, fixed-income debt instruments with maturities that approximate the expected payment of plan obligations, while the expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category. Changes in these assumptions can have a material impact on the amounts reported in the Corporation’s financial statements.

Asset Retirement Obligations: The Corporation has material legal obligations to remove and dismantle long lived assets and to restore land or seabed at certain exploration and production locations. In accordance with

generally accepted accounting principles, the Corporation recognizes a liability for the fair value of required asset retirement obligations. In addition, the fair value of any legally required conditional asset retirement obligations is recorded if the liability can be reasonably estimated. The Corporation capitalizes such costs as a component of the carrying amount of the underlying assets in the period in which the liability is incurred. In order to measure these obligations, the Corporation estimates the fair value of the obligations by discounting the future payments that will be required to satisfy the obligations. In determining these estimates, the Corporation is required to make several assumptions and judgments related to the scope of dismantlement, timing of settlement, interpretation of legal requirements, inflationary factors and discount rate. In addition, there are other external factors which could significantly affect the ultimate settlement costs for these obligations including: changes in environmental regulations and other statutory requirements, fluctuations in industry costs and foreign currency exchange rates, and advances in technology. As a result, the Corporation’s estimates of asset retirement obligations are subject to revision due to the factors described above. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values.

Changes in Accounting Policies

The FASB Accounting Standards Codification (ASC) became effective on July 1, 2009. The ASC combined multiple sources of authoritative accounting literature into a single source of authoritative GAAP organized by accounting topic. Since the ASC was not intended to change existing GAAP, the only impact on the Corporation’s financial statements was that specific references to accounting principles have been changed to refer to the ASC.

Effective January 1, 2009, the Corporation adopted the FASB accounting standard for the accounting for and reporting of noncontrolling interests in a consolidated subsidiary (ASC 810 — Consolidation, originally issued as FAS 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51). As required, the Corporation retrospectively applied the presentation and disclosure requirements of this standard. At December 31, 2009 and December 31, 2008 noncontrolling interests of $144 million and $84 million, respectively, have been classified as a component of equity. Prior to adoption, noncontrolling interests were classified in Other liabilities. Net income (loss) attributable to the noncontrolling interests must also be separately reported in the Statement of Consolidated Income. Certain other amounts in the consolidated financial statements and footnotes have been reclassified to conform with the presentation requirements of this standard.

Effective January 1, 2009, the Corporation adopted the FASB accounting standard that expanded the qualitative, quantitative and credit risk disclosure requirements related to an entity’s use of derivative instruments (ASC 815 — Derivatives and Hedging, originally issued as FAS 161, Disclosures about Derivative Instruments and Hedging Activities). See Note 14, Risk Management and Trading Activities, for these disclosures.

Effective January 1, 2009, the Corporation also adopted the FASB staff position that requires the application of the fair value measurement and disclosure provisions to nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis (ASC 820 — Fair Value Measurements and Disclosures, originally issued as FASB Staff Position No. 157-2, Effective Date of FASB Statement No. 157). Such fair value measurements are determined based on the same fair value hierarchy of inputs required to measure the fair value of financial assets and liabilities. The impact of this accounting standard was not material to the Corporation’s consolidated financial statements.

Effective June 30, 2009, the Corporation adopted the FASB accounting standard which provides guidance on the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued (ASC 855 — Subsequent Events, originally issued as FAS 165, Subsequent Events). The adoption of this standard did not impact the Corporation’s existing practice of evaluating subsequent events through the date the financial statements are issued.

In January 2010, the FASB adopted an accounting standards update (ASU) Extractive Activities — Oil and Gas (ASC 932 — Oil and Gas Reserve Estimation and Disclosures) which is effective for financial statements for the year ended December 31, 2009 and amends the requirements for oil and gas reserve estimation and disclosures. The objective of the ASU was to align accounting standards with the previously issued SEC requirements on oil and gas reserve estimation and disclosure. The main provisions of the ASU are to expand the definition of oil and gas producing activities to include the extraction of resources which are saleable as synthetic oil or gas, to change the price assumption used for reserve estimation and future cash flows to a twelve month average from the year-end

price and to amend the geographic disclosure requirements for reporting reserves and other supplementary oil and gas data. See the Supplementary Oil and Gas Data for these disclosures.

Recently Issued Accounting Standards

In June 2009, the FASB amended existing accounting standards to eliminate the concept of a qualifying special-purpose entity (ASC 860 — Transfers and Servicing, originally issued as FAS 166, Accounting for Transfers of Financial Assets — an amendment of FASB Statement No. 140), which did not require consolidation under existing GAAP. The FASB also amended existing accounting standards to limit the circumstances in which transferred financial assets should be derecognized (ASC 810 — Consolidation, originally issued as FAS 167, Amendments to FASB Interpretation No. FIN 46(R)). The amended standards require additional analysis of variable interest entities to determine if consolidation is necessary. The adoption of these standards will not have a material impact on the Corporation’s financial statements. As required, the Corporation will adopt the provisions of these standards effective January 1, 2010.

Environment, Health and Safety

The Corporation has a values-based, socially-responsible strategy focused on improving environment, health and safety performance and making a positive impact on communities where it does business. The strategy is reflected in the Corporation’s environment, health, safety and social responsibility (EHS & SR) policies and by environment and safety management systems that help protect the Corporation’s workforce, customers and local communities. The Corporation’s management systems are designed to uphold or exceed international standards and are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance. Improved performance may, in the short-term, increase the Corporation’s operating costs and could also require increased capital expenditures to reduce potential risks to assets, reputation and license to operate. In addition to enhanced EHS & SR performance, improved productivity and operational efficiencies may be realized as collateral benefits from investments in EHS & SR. The Corporation has programs in place to evaluate regulatory compliance, audit facilities, train employees, prevent and manage risks and emergencies and to generally meet corporate EHS & SR goals.

The Corporation and HOVENSA produce and the Corporation distributes fuel oils in the United States. Proposals by state regulatory agencies and legislatures have been made that would require a lower sulfur content of fuel oils. If adopted, these proposals could require capital expenditures by the Corporation and HOVENSA to meet the required sulfur content standards.

As described in Item 3, Legal Proceedings, in 2003 the Corporation and HOVENSA began discussions with the U.S. EPA regarding the EPA’s Petroleum Refining Initiative (PRI). The PRI is an ongoing program that is designed to reduce certain air emissions at all U.S. refineries. Since 2000, the EPA has entered into settlements addressing these emissions with petroleum refining companies that control over 90% of the domestic refining capacity. Negotiations with the EPA are continuing and substantial progress has been made toward resolving this matter for both the Corporation and HOVENSA. While the effect on the Corporation of the Petroleum Refining Initiative cannot be estimated until a final settlement is reached and entered by a court, additional significant future capital expenditures and operating expenses will likely be incurred by HOVENSA over a number of years. The amount of penalties, if any, is not expected to be material.

The Corporation has undertaken a program to assess, monitor and reduce the emission of greenhouse gases, including carbon dioxide and methane. The Corporation recognizes that climate change is a global environmental concern. The Corporation is committed to the responsible management of greenhouse gas emissions from our existing assets and future developments and is implementing a strategy to control our carbon emissions.

The Corporation will have continuing expenditures for environmental assessment and remediation. Sites where corrective action may be necessary include gasoline stations, terminals, onshore exploration and production facilities, refineries (including solid waste management units under permits issued pursuant to the Resource Conservation and Recovery Act) and, although not currently significant, “Superfund” sites where the Corporation has been named a potentially responsible party.

The Corporation accrues for environmental assessment and remediation expenditures for known sites when the future costs are probable and reasonably estimable. At year-end 2009, the Corporation’s reserve for estimated environmental liabilities was approximately $55 million. The Corporation’s environmental assessment and remediation expenditures were approximately $11 million in each of the years 2009, 2008 and 2007. The Corporation expects that existing reserves for environmental liabilities are sufficient for costs to assess and remediate known sites. The Corporation anticipates capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, of approximately $50 million in 2010.

Forward-Looking Information

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures about Market Risk, 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, market risk and environmental disclosures, off-balance sheet arrangements and contractual obligations and contingencies include 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.

In the normal course of its business, the Corporation is exposed to commodity risks related to changes in the price of crude oil, natural gas, refined products and electricity, as well as to changes in interest rates and foreign currency values. The Corporation also has trading operations, principally through a 50% voting interest in a consolidated partnership that trades energy commodities and energy derivatives. These activities are also exposed to commodity risks primarily related to the prices of crude oil, natural gas and refined products. The following describes how these risks are controlled and managed.

Controls: The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include volumetric, term and value-at-risk limits. The chief risk officer must approve the use of new instruments or commodities. Risk limits are monitored and reported on daily to business units and to senior management. The Corporation’s risk management department also performs independent verifications of sources of fair values and validations of valuation models. These controls apply to all of the Corporation’s risk management and trading activities, including the consolidated trading partnership. The Corporation’s treasury department is responsible for administering foreign exchange rate and interest rate hedging programs.

The Corporation uses value-at-risk to monitor and control commodity risk within its trading and risk management 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. Results may vary from time to time as strategies change in trading activities or hedging levels change in risk management activities.

Instruments: The Corporation primarily uses forward commodity contracts, foreign exchange forward contracts, futures, swaps, options and energy commodity based securities in its risk management and trading activities. These contracts are generally widely traded instruments with standardized terms. The following describes these instruments and how the Corporation uses them:

Risk Management Activities

Energy marketing activities: In its energy marketing activities, the Corporation sells refined petroleum products, natural gas and electricity principally to commercial and industrial businesses at fixed and floating prices for varying periods of time. Commodity contracts such as futures, forwards, swaps and options together with physical assets, such as storage, are used to obtain supply and reduce margin volatility or lower costs related to sales contracts with customers.

Corporate risk management: Corporate risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas produced by the Corporation or to reduce exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to reduce risk in the selling price of a portion of the Corporation’s crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which the Corporation does business with the intent of reducing exposure to foreign currency fluctuations. Interest rate swaps may also be used, generally to convert fixed rate interest payments to floating.

The Corporation uses foreign exchange contracts to reduce its exposure to fluctuating foreign exchange rates by entering into formal contracts for various currencies including the British pound, the Euro and the Thai baht. At December 31, 2009 the Corporation had a payable of $16 million related to foreign exchange contracts maturing in 2010. The fair value of the foreign exchange contracts was also a payable of $16 million at December 31, 2009. The change in fair value of the foreign exchange contracts from a 20% strengthening of the US dollar exchange rate is estimated to be approximately $172 million at December 31, 2009.

The Corporation’s debt of $4,467 million has a fair value of $5,073 million at December 31, 2009. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $120 million at December 31, 2009.

Value at risk

Following is the value at risk for the Corporation’s energy marketing and risk management activities:

At December 31

Average

High

Low

Trading Activities

Trading activities are conducted principally through a trading partnership in which the Corporation has a 50% voting interest. This consolidated entity intends to generate earnings through various strategies primarily using energy commodities, securities and derivatives. The Corporation also takes trading positions for its own account.

Following is the value at risk for the Corporation’s trading activities:

Derivative trading transactions are marked-to-market and unrealized gains or losses are reflected in income currently. Gains or losses from sales of physical products are recorded at the time of sale. Total realized gains (losses) on trading activities amounted to $642 million in 2009 and $(317) million in 2008. The following table provides an assessment of the factors affecting the changes in fair value of trading activities and represents 100% of the trading partnership and other trading activities.

Fair value of contracts outstanding at the beginning of the year

Change in fair value of contracts outstanding at the beginning of the year and still outstanding at the end of the year

Reversal of fair value for contracts closed during the year

Fair value of contracts entered into during the year and still outstanding

Fair value of contracts outstanding at the end of the year

The following table summarizes the sources of fair values of derivatives used in the Corporation’s trading activities at December 31, 2009:

Source of fair value

Level 1

Level 2

Level 3

The following table summarizes the receivables net of cash margin and letters of credit relating to the Corporation’s trading activities and the credit ratings of counterparties at December 31:

Investment grade determined by outside sources

Investment grade determined internally*

Less than investment grade

Fair value of net receivables outstanding at the end of the year

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2009.

The Corporation’s independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2009, as stated in their report, which is included herein.

/s/ John P. Rielly

/s/ John B. Hess

February 26, 2010

The Board of Directors and Stockholders

Hess Corporation

We have audited Hess Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Hess Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Hess Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009 based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Hess Corporation and consolidated subsidiaries as of December 31, 2009 and 2008, and the related statements of consolidated income, cash flows, and equity and comprehensive income of Hess Corporation and consolidated subsidiaries for each of the three years in the period ended December 31, 2009, and our report dated February 26, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young, LLP

New York, New York

Report of Independent Registered Public Accounting Firm

We have audited the accompanying consolidated balance sheet of Hess Corporation and consolidated subsidiaries (the “Corporation”) as of December 31, 2009 and 2008, and the related statements of consolidated income, cash flows, and equity and comprehensive income for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Hess Corporation and consolidated subsidiaries at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Corporation adopted new oil and gas reserve estimation and disclosure requirements effective December 31, 2009. Also, as discussed in Note 1 to the consolidated financial statements, the Corporation adopted the guidance originally issued in Financial Accounting Standards Board (“FASB”) Financial Accounting Standard 160, Noncontrolling Interests in Consolidated Financial Statements (codified in FASB Accounting Standards Codification Topic 810, Consolidation), effective January 1, 2009.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hess Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2010 expressed an unqualified opinion thereon.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

ASSETS

CURRENT ASSETS

Cash and cash equivalents

Accounts receivable

Trade

Other

Inventories

Other current assets

Total current assets

INVESTMENTS IN AFFILIATES

HOVENSA L.L.C.

Other

Total investments in affiliates

PROPERTY, PLANT AND EQUIPMENT

Total — at cost

Less reserves for depreciation, depletion, amortization and lease impairment

Property, plant and equipment — net

GOODWILL

DEFERRED INCOME TAXES

OTHER ASSETS

TOTAL ASSETS

CURRENT LIABILITIES

Accounts payable

Accrued liabilities

Taxes payable

Current maturities of long-term debt

Total current liabilities

LONG-TERM DEBT

ASSET RETIREMENT OBLIGATIONS

OTHER LIABILITIES AND DEFERRED CREDITS

Total liabilities

EQUITY

Common stock, par value $1.00

Authorized: 600,000 shares

Issued: 2009 — 327,229 shares; 2008 — 326,133 shares

Capital in excess of par value

Retained earnings

Accumulated other comprehensive income (loss)

Total Hess Corporation stockholders’ equity

Noncontrolling interests

Total equity

TOTAL LIABILITIES AND EQUITY

The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and production activities.

See accompanying notes to consolidated financial statements.

REVENUES AND NON-OPERATING INCOME

Sales (excluding excise taxes) and other operating revenues

Equity in income (loss) of HOVENSA L.L.C.

Gain on asset sales

Other, net

Total revenues and non-operating income

COSTS AND EXPENSES

Cost of products sold (excluding items shown separately below)

Production expenses

Marketing expenses

Other operating expenses

General and administrative expenses

Interest expense

INCOME BEFORE INCOME TAXES

Provision for income taxes

NET INCOME

Less: Net income (loss) attributable to noncontrolling interests

NET INCOME ATTRIBUTABLE TO HESS CORPORATION

BASIC NET INCOME PER SHARE

DILUTED NET INCOME PER SHARE

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (DILUTED)

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

Adjustments to reconcile net income to net cash provided by operating activities

Depreciation, depletion and amortization

Exploratory dry hole costs

Lease impairment

Pre-tax gain on asset sales

Benefit for deferred income taxes

Distributed earnings of HOVENSA L.L.C., net

Stock compensation expense

Changes in other operating assets and liabilities:

(Increase) decrease in accounts receivable

Increase in inventories

Increase (decrease) in accounts payable and accrued liabilities

Increase (decrease) in taxes payable

Changes in other assets and liabilities

Net cash provided by operating activities

CASH FLOWS FROM INVESTING ACTIVITIES

Proceeds from asset sales

Payments received on notes receivable

Net cash used in investing activities

CASH FLOWS FROM FINANCING ACTIVITIES

Net (repayments) borrowings of debt with maturities of 90 days or less

Debt with maturities of greater than 90 days

Borrowings

Repayments

Cash dividends paid

Payments to noncontrolling interests, net

Employee stock options exercised, including income tax benefits

Net cash provided by (used in) financing activities

NET INCREASE IN CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR

CASH AND CASH EQUIVALENTS AT END OF YEAR

Balance at January 1, 2007

Net Income

Deferred gains (losses) on cash flow hedges, after tax

Effect of hedge losses recognized in income

Net change in fair value of cash flow hedges

Change in post retirement plan liabilities, after tax

Change in foreign currency translation adjustment and other

Total Comprehensive Income

Activity related to restricted common stock awards, net

Employee stock options, including income tax benefits

Cash dividends declared

Payments to noncontrolling interests, net

Balance at December 31, 2007

Deferred gain (losses) on cash flow hedges, after tax

Effect of adoption of fair value measurements accounting standards

Balance at December 31, 2008

Net Income

Balance at December 31, 2009

Nature of Business: Hess Corporation and its subsidiaries (the Corporation) engage in the exploration for and the development, production, purchase, transportation and sale of crude oil and natural gas. These activities are conducted principally in Algeria, Australia, Azerbaijan, Brazil, Colombia, Denmark, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia, Libya, Malaysia, Norway, Peru, Russia, Thailand, the United Kingdom and the United States. In addition, the Corporation manufactures, purchases, transports, markets and trades, refined petroleum and other energy products. The Corporation owns 50% of HOVENSA L.L.C. (HOVENSA), a refinery joint venture in the United States Virgin Islands. An additional refining facility, terminals and retail gasoline stations, most of which include convenience stores, are located on the East Coast of the United States.

In preparing financial statements in conformity with U.S. generally accepted accounting principles (GAAP), management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and revenues and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are oil and gas reserves, asset valuations, depreciable lives, pension liabilities, legal and environmental obligations, asset retirement obligations and income taxes. In the preparation of these financial statements, the Corporation has evaluated subsequent events through the date the financial statements are issued.

Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which the Corporation owns more than a 50% voting interest or entities that the Corporation controls. The Corporation’s undivided interests in unincorporated oil and gas exploration and production ventures are proportionately consolidated.

Investments in affiliated companies, 20% to 50% owned, including HOVENSA, are stated at cost of acquisition plus the Corporation’s equity in undistributed net income since acquisition. The Corporation consolidates the trading partnership in which it owns a 50% voting interest and over which it exercises control.

Intercompany transactions and accounts are eliminated in consolidation.

Revenue Recognition: The Corporation recognizes revenues from the sale of crude oil, natural gas, petroleum products and other merchandise when title passes to the customer. Sales are reported net of excise and similar taxes in the Statement of Consolidated Income. The Corporation recognizes revenues from the production of natural gas properties based on sales to customers. Differences between E&P natural gas volumes sold and the Corporation’s share of natural gas production are not material. Revenues from natural gas and electricity sales by the Corporation’s marketing operations are recognized based on meter readings and estimated deliveries to customers since the last meter reading.

In its exploration and production activities, the Corporation enters into crude oil purchase and sale transactions with the same counterparty that are entered into in contemplation of one another for the primary purpose of changing location or quality. Similarly, in its marketing activities, the Corporation enters into refined product purchase and sale transactions with the same counterparty. These arrangements are reported net in Sales and other operating revenues in the Statement of Consolidated Income.

Derivatives: The Corporation utilizes derivative instruments for both risk management and trading activities. In risk management activities, the Corporation uses futures, forwards, options and swaps, individually or in combination, to mitigate its exposure to fluctuations in prices of crude oil, natural gas, refined products and electricity, as well as changes in interest and foreign currency exchange rates. In trading activities, the Corporation, principally through a consolidated partnership, trades energy commodities derivatives, including futures, forwards, options and swaps based on expectations of future market conditions.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges) or hedges of firm commitments (fair value hedges). The effective portion of changes in fair value of derivatives that are designated as cash flow hedges is recorded as a component of other comprehensive income (loss). Amounts included in Accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of derivatives designated as cash flow hedges is recorded currently in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.

Cash and Cash Equivalents: Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have maturities of three months or less when acquired.

Inventories: Inventories are valued at the lower of cost or market. For refined product inventories valued at cost, the Corporation uses principally the last-in, first-out (LIFO) inventory method. For the remaining inventories, cost is generally determined using average actual costs.

Exploration and Development Costs: Exploration and production activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.

The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors.

Depreciation, Depletion and Amortization: The Corporation records depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production equipment and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives. Retail gas stations and equipment related to a leased property, are depreciated over the estimated useful lives not to exceed the remaining lease period. The Corporation records the cost of acquired customers in its energy marketing activities as intangible assets and amortizes these costs on the straight-line method over the expected renewal period based on historical experience.

Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying assets.

Asset Retirement Obligations: The Corporation has material legal obligations to remove and dismantle long-lived assets and to restore land or seabed at certain exploration and production locations. The Corporation recognizes a liability for the fair value of legally required asset retirement obligations associated with long-lived assets in the period in which the retirement obligations are incurred. In addition, the fair value of any legally required conditional asset retirement obligations is recorded if the liability can be reasonably estimated. The Corporation capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets.

Impairment of Long-Lived Assets: The Corporation reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted future 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 generally determined by discounting anticipated future net cash flows. In the case of oil and gas fields, the net present value of future 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 and discounted at a risk-adjusted rate. 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 the average prices used in the standardized measure of discounted future net cash flows.

Impairment of Equity Investees: The Corporation reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques.

Impairment of Goodwill: Goodwill is tested for impairment annually in the fourth quarter or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable. This impairment test is calculated at the reporting unit level, which for the Corporation’s goodwill is the Exploration and Production operating segment. The Corporation identifies potential impairments by comparing the fair value of the reporting unit to its book value, including goodwill. If the fair value of the reporting unit exceeds the carrying amount, goodwill is not impaired. If the carrying value exceeds the fair value, the Corporation calculates the possible impairment loss by comparing the implied fair value of goodwill with the carrying amount. If the implied fair value of goodwill is less than the carrying amount, an impairment would be recorded.

Income Taxes: Deferred income taxes are determined using the liability method. The Corporation regularly assesses the realizability of deferred tax assets, based on estimates of future taxable income, the availability of tax planning strategies, the existence of appreciated assets, the available carryforward periods for net operating losses and other factors. If it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount expected to be realized. In addition, the Corporation recognizes the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. Additionally, the Corporation has income taxes which have been deferred on intercompany transactions eliminated in consolidation related to transfers of property, plant and equipment remaining within the consolidated group. The amortization of these income taxes deferred on intercompany transactions will occur ratably with the recovery through depletion and depreciation of the carrying value of these assets. The Corporation does not provide for deferred U.S. income taxes for that portion of undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations. The Corporation classifies interest and penalties associated with uncertain tax positions as income tax expense.

Fair Value Measurements: The Corporation adopted a new accounting standard for fair value measurements, effective January 1, 2008 (ASC 820 — Fair Value Measurements and Disclosures, originally issued as FAS 157, Fair Value Measurements). The standard establishes a hierarchy for the inputs used to measure fair value based on the source of the input, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Multiple inputs may be used to measure fair value, however, the level of fair value for each financial asset or liability is based on the lowest significant input level within this fair value hierarchy.

frequency and volume to assure liquidity. The fair value of certain of the Corporation’s exchange traded futures and options are considered Level 1.

Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. The Corporation utilizes fair value measurements based on Level 2 inputs for certain forwards, swaps and options. The liability related to the Corporation’s crude oil hedges is classified as Level 2.

Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. For example, in its energy marketing business, the Corporation sells natural gas and electricity to customers and offsets the price exposure by purchasing forward contracts. The fair value of these sales and purchases may be based on specific prices at less liquid delivered locations, which are classified as Level 3. There may be offsets to these positions that are priced based on more liquid markets, which are, therefore, classified as Level 1 or Level 2.

The impact of adopting the fair value measurements standard was not material to the Corporation’s results of operations. Upon adoption in 2008, the Corporation recorded a reduction in the net deferred hedge losses reflected in Accumulated other comprehensive income, which increased equity by $193 million, after income taxes.

Effective December 31, 2008, the Corporation applied the provisions of a new accounting standard for the accounting for liabilities measured at fair value with a third-party credit enhancement (ASC 820 — Fair Value Measurements and Disclosures, originally issued as Emerging Issues Task Force 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement). Upon adoption, the Corporation revalued certain derivative liabilities collateralized by letters of credit to reflect the Corporation’s credit rating rather than the credit rating of the issuing bank. The adoption resulted in an increase in Sales and other operating revenues of approximately $13 million and an increase in Accumulated other comprehensive income of approximately $78 million, with a corresponding decrease in derivative liabilities recorded within Accounts payable.

Retirement Plans: The Corporation recognizes the underfunded status of defined benefit postretirement plans on the balance sheet. For the Corporation’s pension plans, the underfunded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. The Corporation recognizes the net changes in the funded status of these plans in the year in which such changes occur.

Share-Based Compensation: The fair value of all share-based compensation is expensed and recognized on a straight-line basis over the vesting period of the awards.

Foreign Currency Translation: The U.S. dollar is the functional currency (primary currency in which business is conducted) for most foreign operations. Adjustments resulting from translating monetary assets and liabilities that are denominated in a non-functional currency into the functional currency are recorded in Other, net within Sales and other operating revenues in the Statement of Consolidated Income. For operations that do not use the U.S. dollar as the functional currency, adjustments resulting from translating foreign currency assets and liabilities into U.S. dollars are recorded in a separate component of equity titled Accumulated other comprehensive income (loss).

Maintenance and Repairs: Maintenance and repairs are expensed as incurred, including costs of refinery turnarounds. Capital improvements are recorded as additions in Property, plant and equipment.

Environmental Expenditures: The Corporation accrues and expenses environmental costs to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. The

Corporation capitalizes environmental expenditures that increase the life or efficiency of property or that reduce or prevent future adverse impacts to the environment.

Changes in Accounting Policies: The Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) became effective on July 1, 2009. The ASC combined multiple sources of authoritative accounting literature into a single source of authoritative GAAP organized by accounting topic. Since the ASC was not intended to change existing GAAP, the only impact on the Corporation’s financial statements was that specific references to accounting principles have been changed to refer to the ASC.

Effective January 1, 2009, the Corporation adopted the FASB accounting standard for the accounting for and reporting of noncontrolling interests in a consolidated subsidiary (ASC 810 — Consolidation, originally issued as FAS 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51). As required, the Corporation retrospectively applied the presentation and disclosure requirements of this standard. At December 31, 2009 and December 31, 2008, noncontrolling interests of $144 million and $84 million, respectively, have been classified as a component of equity. Prior to adoption, noncontrolling interests were classified in Other liabilities. Net income (loss) attributable to the noncontrolling interests must also be separately reported in the Statement of Consolidated Income. Certain other amounts in the consolidated financial statements and footnotes have been reclassified to conform with the presentation requirements of this standard.

In January 2010, the FASB adopted an accounting standards update (ASU) Extractive Activities — Oil and Gas (ASC 932) Oil and Gas Reserve Estimation and Disclosures, which is effective for year-end 2009 reporting and amends the requirements for oil and gas reserve estimation and disclosures. The objective of the ASU was to align accounting standards with the previously issued Securities and Exchange Commission (SEC) requirements on oil and gas reserve estimation and disclosure. The main provisions of the ASU are to expand the definition of oil and gas producing activities to include the extraction of resources which are saleable as synthetic oil or gas, to change the price assumption used for reserve estimation and future cash flows to a twelve month average from the year-end price and to amend the geographic disclosure requirements for reporting reserves and other supplementary oil and gas data. See the Supplementary Oil and Gas Data for these disclosures.

Recently Issued Accounting Standards: In June 2009, the FASB amended existing accounting standards to eliminate the concept of a qualifying special-purpose entity (ASC 860 — Transfers and Servicing, originally issued as FAS 166, Accounting for Transfers of Financial Assets — an amendment of FASB Statement No. 140), which did not require consolidation under existing GAAP. The FASB also amended existing standards to limit the circumstances in which transferred financial assets should be derecognized (and ASC 810 — Consolidation, originally issued as FAS 167, Amendments to FASB Interpretation No. FIN 46(R)). The amended standards require

additional analysis of variable interest entities to determine if consolidation is necessary. The adoption of these standards will not have a material impact on the Corporation’s financial statements. As required, the Corporation will adopt the provisions of these standards effective January 1, 2010.

2009: The Corporation acquired for $74 million a 50% interest in Blocks PM301 and PM302 in Malaysia, which are adjacent to Block A-18 of the Joint Development Area of Malaysia/Thailand (JDA) and contain an extension of the Bumi Field. The Corporation also acquired 37 previously leased retail gasoline stations, primarily through the assumption of $65 million of fixed rate notes.

2008: The Corporation acquired the remaining 22.5% interest in its Gabonese subsidiary for $285 million, of which $210 million was allocated to proved properties. The Corporation expanded its energy marketing business by acquiring fuel oil, natural gas, and electricity customer accounts, and a terminal and related assets, for an aggregate of approximately $100 million.

2007: The Corporation completed the acquisition of a 28% interest in the Genghis Khan oil and gas development located in the deepwater Gulf of Mexico on Green Canyon Blocks 652 and 608 for $371 million, of which $342 million was allocated to proved and unproved properties and the remainder to wells and equipment. This transaction was accounted for as an asset acquisition. Genghis Khan has been unitized with the Shenzi development.

The Corporation completed the sale of its interests in the Scott and Telford fields located in the United Kingdom North Sea for $93 million and recorded a gain of $21 million ($15 million after income taxes) that is included in Other, net in the Statement of Consolidated Income.

Inventories at December 31 are as follows:

Crude oil and other charge stocks

Refined products and natural gas

Less: LIFO adjustment

Merchandise, materials and supplies

The percentage of LIFO inventory to total crude oil, refined products and natural gas inventories was 64% and 60% at December 31, 2009 and 2008, respectively. In 2009, the Corporation recorded a pre-tax charge of $25 million ($18 million after income taxes) to write down materials inventories in Equatorial Guinea and the United States, the majority of which was recorded in Production expenses. During 2007, the Corporation reduced LIFO inventories, which are carried at lower costs than current inventory costs. The effect of the LIFO inventory liquidation was to decrease Cost of products sold by approximately $38 million ($24 million after income taxes).

The Corporation has an investment in HOVENSA L.L.C., a 50% joint venture with Petroleos de Venezuela, S.A. (PDVSA), which is accounted for using the equity method. HOVENSA owns and operates a refinery in the U.S. Virgin Islands. Summarized financial information for HOVENSA as of December 31 and for the years then ended follows:

Summarized Balance Sheet, at December 31

Cash and cash equivalents

Other current assets

Net fixed assets

Other assets

Current liabilities

Long-term debt

Deferred liabilities and credits

Members’ equity

Summarized Income Statement, for the years ended December 31

Total revenues

Costs and expenses

Net income (loss)

Hess Corporation’s share*

Summarized Cash Flow Statement, for the years ended December 31

Net cash provided by (used in):

Operating activities

Investing activities

Financing activities

Net increase (decrease) in cash and cash equivalents

The Corporation received cash distributions from HOVENSA of $50 million in 2008 and $300 million during 2007.

The Corporation guarantees the payment of up to 50% of the value of HOVENSA’s crude oil purchases from certain suppliers other than PDVSA. The guarantee amounted to $121 million at December 31, 2009. This amount fluctuates based on the volume of crude oil purchased and the related crude oil prices. In addition, the Corporation has agreed to provide funding up to $15 million to the extent HOVENSA does not have funds to meet its senior debt obligations.

Property, plant and equipment at December 31 consists of the following:

Unproved properties

Proved properties

Wells, equipment and related facilities

Total — at cost

Less: reserves for depreciation, depletion, amortization and lease impairment

Property, plant and equipment — net

In December 2009, the Corporation agreed to a strategic exchange of all of its interests in Gabon and the Clair Field in the United Kingdom for additional interests in the Valhall and Hod fields offshore Norway. The transaction, which has an effective date of January 1, 2010, is subject to various regulatory and other approvals. In addition, the partners are in discussions regarding the applicability of pre-emption to this transaction. In January 2010, the Corporation completed the sale of its interest in the Jambi Merang Field in Indonesia. The Corporation has classified its interests in Gabon, the Clair Field and Jambi Merang Field as assets held for sale. At December 31, 2009, the carrying amount of these assets totaling $717 million were reported in Other current assets, and asset retirement obligations and deferred income taxes totaling $254 million were reported in Accrued liabilities.

The Corporation recorded asset impairments totaling $52 million ($26 million after income taxes) in 2009, $30 million ($17 million after income taxes) in 2008, and $112 million ($56 million after income taxes) in 2007. These impairments are reflected in Depreciation, depletion and amortization.

The following table discloses the amount of capitalized exploratory well costs pending determination of proved reserves at December 31, and the changes therein during the respective years:

Beginning balance at January 1

Additions to capitalized exploratory well costs pending the determination of proved reserves

Reclassifications to wells, facilities, and equipment based on the determination of proved reserves

Capitalized exploratory well costs charged to expense

Ending balance at December 31

Number of wells at end of year

The preceding table excludes exploratory dry hole costs of $193 million, $203 million and $65 million in 2009, 2008 and 2007, respectively, which were incurred and subsequently expensed in the same year.

At December 31, 2009, exploratory drilling costs capitalized in excess of one year past completion of drilling were as follows (in millions):

2008

2007

2006

2003 to 2005

The capitalized well costs in excess of one year relate to 15 projects. Approximately 72% of the capitalized well costs in excess of one year relate to the Pony and Tubular Bells projects in the deepwater Gulf of Mexico where development planning is underway. In addition, the Corporation plans to drill another appraisal well at Pony in 2010. Approximately 12% of the costs in excess of one year relate to Western Australia (WA-390-P) where further drilling is planned in 2010. The remainder of the costs relate to projects where further drilling is planned or development planning and other assessment activities are ongoing to determine the economic and operating viability of the projects.

The following table describes changes to the Corporation’s asset retirement obligations:

Asset retirement obligations at January 1

Liabilities incurred

Liabilities settled or disposed of

Accretion expense

Revisions

Foreign currency translation

Asset retirement obligations at December 31

Less: current obligations

Long-term obligations at December 31

Revisions are primarily attributable to changes in service and equipment costs in the oil and gas industry.

Long-term debt at December 31 consists of the following:

Asset-backed credit facility

Fixed rate debentures:

7.4% due 2009

6.7% due 2011

7.0% due 2014

8.1% due 2019

7.9% due 2029

7.3% due 2031

7.1% due 2033

6.0% due 2040

Total fixed rate debentures

Fixed rate notes, weighted average rate 8.5%, due through 2023

Project lease financing, weighted average rate 5.1%, due through 2014

Pollution control revenue bonds, weighted average rate 5.9%, due through 2034

Other loans, weighted average rate 9.0%, due through 2019

Less: amount included in current maturities

In February 2009, the Corporation issued $250 million of 5 year senior unsecured notes with a coupon of 7% and $1 billion of 10 year senior unsecured notes with a coupon of 8.125%. The majority of the proceeds were used to repay debt under the revolving credit facility and outstanding borrowings on other credit facilities. In December 2009, the Corporation issued $750 million of 30 year bonds with a coupon of 6% and tendered for the $662 million of bonds due in August 2011. The Corporation completed the purchase of $546 million of the 2011 bonds in December 2009. The Corporation recorded a charge of $54 million related to the repurchase in Other, net within the Statement of Consolidated Income ($34 million after income taxes). The remaining $116 million of the 2011 bonds, classified as Current maturities of long term debt at December 31, 2009, was redeemed in January 2010, resulting in a charge of approximately $11 million ($7 million after income taxes).

The aggregate long-term debt maturing during the next five years is as follows (in millions): 2010 — $148 (included in current liabilities); 2011 — $32; 2012 — $34; 2013 — $37 and 2014 — $333.

At December 31, 2009, the Corporation’s fixed rate debentures have a principal amount of $4,166 million ($4,145 million net of unamortized discount). Interest rates on the outstanding fixed rate debentures have a weighted average rate of 7.3%.

The Corporation has a $3.0 billion syndicated revolving credit facility (the facility), which can be used for borrowings and letters of credit, substantially all of which is committed through May 2012. At December 31, 2009, the Corporation has available capacity on the facility of $3.0 billion. Current borrowings under the facility bear interest at 0.4% above the London Interbank Offered Rate and a facility fee of 0.1% per annum is payable on the amount of the facility. The interest rate and facility fee are subject to adjustment if the Corporation’s credit rating changes.

The Corporation has a 364 day asset-backed credit facility securitized by certain accounts receivable from its Marketing and Refining operations. Under the terms of this financing arrangement, the Corporation has the ability

to borrow or issue letters of credit of up to $1.0 billion at December 31, 2009, subject to the availability of sufficient levels of eligible receivables. At December 31, 2009, outstanding letters of credit under this facility were collateralized by a total of $1,326 million of accounts receivable, which are held by a wholly-owned subsidiary. These receivables are only available to pay the general obligations of the Corporation after satisfaction of the outstanding obligations under the asset backed facility.

In 2009, the Corporation assumed an additional $65 million in fixed rate notes in connection with the acquisition of 37 previously leased retail gasoline stations.

The Corporation’s long-term debt agreements contain a financial covenant that restricts the amount of total borrowings and secured debt. At December 31, 2009, the Corporation is permitted to borrow up to an additional $18.1 billion for the construction or acquisition of assets. The Corporation has the ability to borrow up to an additional $3.7 billion of secured debt at December 31, 2009.

Outstanding letters of credit at December 31 were as follows:

Committed lines*

Uncommitted short-term lines*

Of the total letters of credit outstanding at December 31, 2009, $100 million relates to contingent liabilities and the remaining $2,747 million primarily relates to liabilities recorded on the balance sheet.

The total amount of interest paid (net of amounts capitalized) was $335 million, $266 million and $257 million in 2009, 2008 and 2007, respectively. The Corporation capitalized interest of $6 million, $7 million and $50 million in 2009, 2008, and 2007, respectively.

The Corporation awards restricted common stock and stock options under its 2008 Long-Term Incentive Plan. Generally, stock options vest in one to three years from the date of grant, have a 10-year option life, and the exercise price equals or exceeds the market price on the date of grant. Outstanding restricted common stock generally vests in three years from the date of grant.

Share-based compensation expense consists of the following:

Stock options

Restricted stock

Based on restricted stock and stock option awards outstanding at December 31, 2009, unearned compensation expense, before income taxes, will be recognized in future years as follows (in millions): 2010 — $88, 2011 — $42 and 2012 — $4.

The Corporation’s stock option and restricted stock activity consisted of the following:

Outstanding at January 1, 2007

Granted

Exercised

Vested

Forfeited

Outstanding at December 31, 2007

Outstanding at December 31, 2008

Outstanding at December 31, 2009

Exercisable at December 31, 2007

Exercisable at December 31, 2008

Exercisable at December 31, 2009

The table below summarizes information regarding the outstanding and exercisable stock options as of December 31, 2009:

Exercise Prices

$10.00 – $40.00

$40.01 – $50.00

$50.01 – $55.00

$55.01 – $60.00

$60.01 – $120.00

The intrinsic value (or the amount by which the market price of the Corporation’s Common Stock exceeds the exercise price of an option) for outstanding options and exercisable options at December 31, 2009 was $132 million

and $113 million, respectively. At December 31, 2009, assuming forfeitures of 2% per year, 11,900,000 outstanding options are expected to vest at a weighted average exercise price of $53.70 per share. At December 31, 2009, the weighted average remaining term of exercisable options was 6 years.

The Corporation uses the Black-Scholes model to estimate the fair value of employee stock options. The following weighted average assumptions were utilized for stock options awarded:

Risk free interest rate

Stock price volatility

Dividend yield

Expected term in years

Weighted average fair value per option granted

The assumption above for the risk free interest rate is based on the expected terms of the options and is obtained from published sources. The stock price volatility is determined from historical experience using the same period as the expected terms of the options. The expected stock option term is based on historical exercise patterns and the expected future holding period.

In May 2008, shareholders approved the 2008 Long-Term Incentive Plan. The Corporation also has stock options outstanding under a former plan. At December 31, 2009, the number of common shares reserved for issuance under the 2008 Long-Term Incentive Plan is as follows (in thousands):

Total common shares reserved for issuance

Less: stock options outstanding

Available for future awards of restricted stock and stock options

Foreign currency gains (losses) before income taxes amounted to $20 million in 2009, $(212) million in 2008 and $17 million in 2007. The foreign currency loss in 2008 reflects the net effect of significant exchange rate movements in the fourth quarter of 2008 on the remeasurement of assets, liabilities and foreign currency forward contracts by certain foreign businesses. The balances in accumulated other comprehensive income (loss) related to foreign currency translation were reductions in stockholders’ equity of $18 million at December 31, 2009 and $123 million at December 31, 2008.

The Corporation has funded noncontributory defined benefit pension plans for a significant portion of its employees. In addition, the Corporation has an unfunded supplemental pension plan covering certain employees. The unfunded supplemental pension plan provides for incremental pension payments from the Corporation so that total pension payments equal amounts that would have been payable from the Corporation’s principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average salary. Additionally, the Corporation maintains an unfunded postretirement medical plan that provides health benefits to certain qualified retirees from ages 55 through 65. The measurement date for all retirement plans is December 31.

The following table summarizes the Corporation’s benefit obligations and the fair value of plan assets and shows the funded status of the pension and postretirement medical plans:

Change in benefit obligation

Balance at January 1

Service cost

Interest cost

Actuarial (gain) loss

Benefit payments

Plan settlement*

Foreign currency exchange rate changes

Balance at December 31

Change in fair value of plan assets

Actual return on plan assets

Employer contributions

Funded status (plan assets less than benefit obligations) at December 31

Unrecognized net actuarial losses

Net amount recognized

Amounts recognized in the consolidated balance sheet at December 31 consist of the following:

Accrued benefit liability

Accumulated other comprehensive loss*

Net amount recognized

The accumulated benefit obligation for the funded defined benefit pension plans was $1,229 million at December 31, 2009 and $1,032 million at December 31, 2008. The accumulated benefit obligation for the unfunded defined benefit pension plan was $172 million at December 31, 2009 and $149 million at December 31, 2008.

Components of net periodic benefit cost for funded and unfunded pension plans and the postretirement medical plan consisted of the following:

Service cost

Interest cost

Expected return on plan assets

Amortization of unrecognized net actuarial loss

Settlement loss

Net periodic benefit cost

Prior service costs and actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service period of active employees.

The Corporation’s 2010 pension and postretirement medical expense is estimated to be approximately $110 million, of which approximately $50 million relates to the amortization of unrecognized net actuarial losses.

The weighted-average actuarial assumptions used by the Corporation’s funded and unfunded pension plans were as follows:

Weighted-average assumptions used to determine benefit obligations at December 31

Discount rate

Rate of compensation increase

Weighted-average assumptions used to determine net benefit cost for years ended December 31

Expected return on plan assets

The actuarial assumptions used by the Corporation’s postretirement medical plan were as follows:

Assumptions used to determine benefit obligations at December 31

Initial health care trend rate

Ultimate trend rate

Year in which ultimate trend rate is reached

The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year while the assumptions used to determine benefit obligations were established at each year-end. The net periodic benefit

cost and the actuarial present value of benefit obligations are based on actuarial assumptions that are reviewed on an annual basis. The discount rate is developed based on a portfolio of high-quality, fixed-income debt instruments with maturities that approximate the expected payment of plan obligations. The overall expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category.

The Corporation’s investment strategy is to maximize long-term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by the Corporation’s investment committee and include domestic and foreign equities, fixed income, and other investments, including hedge funds, real estate and private equity. Investment managers are prohibited from investing in securities issued by the Corporation unless indirectly held as part of an index strategy. The majority of plan assets are highly liquid, providing ample liquidity for benefit payment requirements. The current target allocations for plan assets are 50% equity securities, 25% fixed income securities (including cash and short-term investment funds) and 25% to all other types of investments. Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels.

The following table provides the fair value of the Plan’s financial assets as of December 31, 2009 in accordance with the fair value measurement hierarchy described in Note 1, Summary of Significant Accounting Policies (in millions):

Cash and short-term investment funds

Equities:

U.S. equities (domestic)

International equities (non-U.S.)

Global equities (domestic and non-U.S.)

Fixed income:

Treasury and government issued(a)

Government related(b)

Mortgage backed securities(c)

Corporate

Other:

Hedge funds

Private equity funds

Real estate funds

Diversified commodities funds

Cash and short-term investment funds consist of cash on hand and short-term investment funds. The short-term investment funds provide for daily investments and redemptions and are valued and carried at a $1 net asset value (NAV) per fund share.

Equities consist of equity securities issued by U.S. and non-U.S. corporations as well as commingled investment funds that invest in equity securities. Individually held equity securities are traded actively on exchanges and price quotes for these shares are readily available. Individual equity securities are classified as Level 1. Commingled investment funds are investment vehicles that are not publicly traded, but whose underlying assets are publicly traded with price quotes readily available. Commingled fund values reflect the NAV per fund

share, derived from the quoted prices in active markets of the underlying securities. Equity commingled funds are classified as Level 2.

Fixed income investments consist of securities issued by the U.S. government, non-U.S. governments, governmental agencies, municipalities and corporations, and agency and non-agency mortgage backed securities. This investment category also includes commingled investment funds that invest in fixed income securities. Individual fixed income securities are generally priced on the basis of evaluated prices from independent pricing services. Such prices are monitored and provided by an independent, third-party custodial firm safekeeping plan assets. Individual fixed income securities are classified as Level 2 or 3. Commingled fund values reflect the NAV per fund share, derived indirectly from observable inputs or from quoted prices in less liquid markets of the underlying securities. Fixed income commingled funds are classified as Level 2.

Other investments consist of exchange-traded real estate investment trust securities as well as commingled fund and limited partnership investments in hedge funds, private equity, real estate and diversified commodities. Exchange-traded securities are classified as Level 1. Commingled fund values reflect the NAV per fund share and are classified as Level 2 or 3. Private equity and real estate limited partnership values reflect information reported by the fund managers, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data and independent appraisals from third-party sources with professional qualifications. Hedge funds, private equity and non-exchange-traded real estate investments are classified as Level 3.

The following table provides changes in financial assets that are measured at fair value based on Level 3 inputs that are held by institutional funds classified as (in millions):

Balance at January 1, 2009

Actual return on plan assets:

Related to assets held at December 31, 2009

Related to assets sold during 2009

Purchases, sales or other settlements

Net transfers in and/or out of Level 3

Balance at December 31, 2009

The Corporation has budgeted contributions of approximately $145 million to its funded pension plans in 2010. The Corporation has not budgeted any contributions to the trust established for the unfunded plan.

Estimated future benefit payments for the funded and unfunded pension plans and the postretirement medical plan, which reflect expected future service, are as follows (in millions):

2010

2011

2012

2013

2014

Years 2015 to 2019

The Corporation also contributes to several defined contribution plans for eligible employees. Employees may contribute a portion of their compensation to the plans and the Corporation matches a portion of the employee

contributions. The Corporation recorded expense of $24 million in 2009, $22 million in 2008, and $19 million in 2007 for contributions to these plans.

The provision for (benefit from) income taxes consisted of:

Federal

Current

Deferred

State

Foreign

Adjustment of deferred tax liability for foreign income tax rate change

Total provision for income taxes

Income (loss) before income taxes consisted of the following:

United States*

Foreign**

Total income before income taxes

A summary of the components of deferred tax liabilities, deferred tax assets and taxes deferred at December 31 follows:

Deferred tax liabilities

Property, plant and equipment and investments

Deferred taxes on undistributed earnings of foreign subsidiaries

Total deferred tax liabilities

Deferred tax assets

Net operating loss carryforwards

Tax credit carryforwards

Property, plant and equipment

Accrued liabilities

Asset retirement obligations

Total deferred tax assets

Valuation allowance

Total deferred tax assets, net

Net deferred tax assets

Net deferred tax assets in the foregoing table include the deferral of the tax consequences of the utilization of approximately $4 billion of net operating loss carryforwards in the United States during 2009 resulting from intercompany transactions eliminated in consolidation related to transfers of property, plant and equipment remaining within the consolidated group. At December 31, 2009, the Corporation has remaining federal net operating loss carryforwards in the United States of approximately $49 million which will expire in 2029. The remaining net operating loss carryforwards relate primarily to foreign operations and expire in years after 2028. At December 31, 2009, the Corporation has alternative minimum tax credit carryforwards of approximately $192 million, which can be carried forward indefinitely. Foreign tax credit carryforwards, which expire in 2010 to 2019 total $623 million. The Corporation also has approximately $45 million of general business credits, substantially all of which expire between 2012 and 2025.

In the consolidated balance sheet at December 31, deferred tax assets and liabilities from the preceding table are netted by taxing jurisdiction, combined with taxes deferred on intercompany transactions, and are recorded in the following captions:

Other current assets

Deferred income taxes (long-term asset)

Accrued liabilities

Deferred income taxes (long-term liability)

The difference between the Corporation’s effective income tax rate and the United States statutory rate is reconciled below:

United States statutory rate

Effect of foreign operations

State income taxes, net of Federal income tax

Other

Below is a reconciliation of the beginning and ending amount of unrecognized tax benefits (millions of dollars):

Balance at January 1

Additions based on tax positions taken in the current year

Additions based on tax positions of prior years

Reductions based on tax positions of prior years

Reductions due to settlements with taxing authorities

Reductions due to lapse of statutes of limitation

Balance at December 31

At December 31, 2009, the unrecognized tax benefits include $197 million, which if recognized, would affect the Corporation’s effective income tax rate. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by up to $25 million due to settlements with taxing authorities.

The Corporation has not recognized deferred income taxes for that portion of undistributed earnings of foreign subsidiaries expected to be indefinitely reinvested in foreign operations. The Corporation had undistributed earnings from foreign subsidiaries expected to be indefinitely reinvested in foreign operations of approximately $3.4 billion at December 31, 2009. If these earnings were not indefinitely reinvested, a deferred tax liability of approximately $1.2 billion would be recognized, not accounting for the potential utilization of foreign tax credits in the United States.

The Corporation and its subsidiaries file income tax returns in the United States and various foreign jurisdictions. The Corporation is no longer subject to examinations by income tax authorities in most jurisdictions for years prior to 2003.

Income taxes paid (net of refunds) in 2009, 2008, and 2007 amounted to $1,177 million, $2,420 million and $1,826 million, respectively. The Corporation had accrued interest and penalties of approximately $17 million as of December 31, 2009 and approximately $6 million as of December 31, 2008.

The following table provides the changes in the Corporation’s outstanding common shares:

Activity related to restricted common stock awards, net

Employee stock options

Conversion of preferred stock

During 2008, the Corporation’s remaining 284,139 outstanding shares of 3% cumulative convertible preferred shares were converted into common stock at a conversion rate of 1.8783 shares of common stock for each preferred share. The Corporation issued 533,697 shares of common stock for the conversion of these preferred shares and fractional shares were settled by cash payments.

The weighted average number of common shares used in the basic and diluted earnings per share computations for each year is summarized below:

Common shares — basic

Effect of dilutive securities

Stock options

Restricted common stock

Convertible preferred stock

Common shares — diluted

The calculation of weighted average common shares excludes the effect of 4,050,000, 425,000 and 715,000 out-of-the-money options for 2009, 2008 and 2007, respectively. Cash dividends on common stock totaled $0.40 per share ($0.10 per quarter) during 2009, 2008 and 2007.

The Corporation and certain of its subsidiaries lease gasoline stations, drilling rigs, tankers, office space and other assets for varying periods under contractual obligations accounted for as operating leases. Certain operating leases provide an option to purchase the related property at fixed prices. At December 31, 2009, future minimum rental payments applicable to non-cancelable operating leases with remaining terms of one year or more (other than oil and gas property leases) are as follows (in millions):

Remaining years

Total minimum lease payments

Less: income from subleases

Net minimum lease payments

Operating lease expenses for drilling rigs used to drill development wells and successful exploration wells are capitalized.

Rental expense was as follows:

Total rental expense

Net rental expense

In the normal course of its business, the Corporation is exposed to commodity risks related to changes in the prices of crude oil, natural gas, refined products and electricity, as well as to changes in interest rates and foreign currency values. The Corporation also has trading operations, principally through a 50% voting interest in a consolidated partnership, that are exposed to commodity price risks primarily related to the prices of crude oil, natural gas and refined products.

The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include volumetric, term and value-at-risk limits. The chief risk officer must approve the use of new instruments or commodities. Risk limits are monitored and reported on daily to business units and to senior management. The Corporation’s risk management department also performs independent verifications of sources of fair values and validations of valuation models. These controls apply to all of the Corporation’s risk management and trading activities, including the consolidated trading partnership. The Corporation’s treasury department is responsible for administering foreign exchange and interest rate hedging programs.

Following is a description of the Corporation’s activities that use derivatives as part of their operations and strategies. Derivatives include both financial instruments and forward purchase and sale contracts. Gross notional amounts of both long and short positions are presented in the volume tables below. These amounts include long and short positions that offset in a closed position and have not reached contractual maturity. Gross notional amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash settlements under the contracts.

Energy Marketing Activities: In its energy marketing activities the Corporation sells refined petroleum products, natural gas and electricity principally to commercial and industrial businesses at fixed and floating prices for varying periods of time. Commodity contracts such as futures, forwards, swaps and options, together with physical assets such as storage, are used to obtain supply and reduce margin volatility or lower costs related to sales contracts with customers.

The table below shows the gross volume of the Corporation’s energy marketing commodity contracts outstanding at December 31, 2009:

Commodity Contracts

Crude oil and refined products (millions of barrels)

Natural gas (millions of mcf)

Electricity (millions of megawatt hours)

At December 31, 2009, a portion of energy marketing commodity contracts are designated as cash flow hedges to hedge variability of expected future cash flows of forecasted supply transactions. The length of time over which the Corporation hedges exposure to variability in future cash flows is predominantly two years or less. For contracts outstanding at December 31, 2009, the maximum duration was five years. The Corporation records the effective portion of changes in the fair value of cash flow hedges as a component of other comprehensive income. Amounts

recorded in Accumulated other comprehensive income are reclassified into Cost of products sold in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of cash flow hedges is recognized immediately in Cost of products sold.

At December 31, 2009, the after-tax deferred losses relating to energy marketing activities recorded in Accumulated other comprehensive income were $303 million ($335 million at December 31, 2008). The Corporation estimates that approximately $224 million of this amount will be reclassified into earnings over the next twelve months. During 2009, 2008 and 2007, the Corporation reclassified after-tax income (losses) from Accumulated other comprehensive income of $(596) million, $112 million and $(81) million, respectively. The amount of gain (loss) from hedge ineffectiveness reflected in earnings in 2009, 2008 and 2007 was $(2) million in 2009, less than $1 million in 2008 and $(5) million in 2007. The change in the fair value of energy marketing cash flow hedges was $(564) million in 2009, $(255) million in 2008 and $(3) million in 2007.

The change in fair value of other energy marketing commodity contracts that are not designated as hedges are recognized currently in earnings. Revenues from the sales contracts are recognized in Sales and other operating revenues, supply contract purchases are recognized in Cost of products sold and net settlements from financial derivatives are recognized in Cost of products sold. Net realized and unrealized pre-tax gains on derivative contracts not designated as hedges amounted to $102 million in 2009.

Corporate Risk Management: Corporate risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas produced by the Corporation or to reduce exposure to foreign currency movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price of a portion of the Corporation’s crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which the Corporation does business with the intent of reducing exposure to foreign currency fluctuations.

The table below shows the gross volume of Corporate risk management derivative instruments outstanding at December 31, 2009:

Commodity contracts, primarily crude oil (millions of barrels)*

Foreign exchange contracts (millions of U.S. dollars)

During 2008, the Corporation closed Brent crude oil cash flow hedges covering 24,000 barrels per day through 2012 by entering into offsetting contracts with the same counterparty. As a result, the valuation of those contracts is no longer subject to change due to price fluctuations. There were no other open hedges of crude oil or natural gas production at December 31, 2009. Hedging activities decreased Exploration and Production earnings by $337 million in 2009, $423 million in 2008 and $244 million in 2007. The pre-tax amount of these hedge losses is reflected in Sales and other operating revenue. The gain (loss) from hedge ineffectiveness reflected in revenue was less than $1 million in 2009, $(13) million in 2008 and $6 million in 2007.

At December 31, 2009, the after-tax deferred losses in Accumulated other comprehensive income relating to Corporate risk management cash flow hedges were $941 million ($1,143 million at December 31, 2008). These deferred losses result from the Brent crude oil hedges referred to above that cover ongoing production of 24,000 barrels per day from 2010 through 2012. The Corporation estimates that approximately $335 million of this amount will be reclassified into earnings over the next twelve months. The pre-tax amount of deferred hedge losses is reflected in Accounts payable and the related income tax benefits are recorded as Deferred income tax assets on the balance sheet.

The change in fair value of foreign exchange contracts are not designated as hedges. Gains or losses in foreign exchange contracts, maturing through 2010, are recognized immediately in Other, net in revenues and non-operating income.

For the year ended December 31, 2009, net pre-tax gains on derivative contracts used for Corporate risk management and not designated as hedges amounted to the following (in millions):

Commodity

Foreign exchange

Trading Activities: Trading activities are conducted principally through a trading partnership in which the Corporation has a 50% voting interest. This consolidated entity intends to generate earnings through various strategies primarily using energy commodities, securities and derivatives. The Corporation also takes trading positions for its own account.

The table below shows the gross volume of the Corporation’s trading derivative instruments outstanding at December 31, 2009:

Other Contracts (millions of U.S. dollars)

Interest rate

Foreign exchange

For the year ended December 31, 2009, pre-tax gains recorded in Sales and other operating revenues from trading activities amounted to the following (in millions):

Interest rate and other

Fair Value Measurements: The Corporation determines fair value in accordance with the fair value measurements accounting standard (ASC 820 — Fair Value Measurements and Disclosures), which established a hierarchy that categorizes the sources of inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Multiple inputs may be used to measure fair value, however, the level of fair value for each financial asset or liability presented below is based on the lowest significant input level within this fair value

hierarchy. The following table provides the fair value of the Corporation’s financial assets and (liabilities) based on this hierarchy:

2009

Derivative contracts

Assets

Liabilities

Other assets and liabilities measured at fair value on a recurring basis

2008

The following table provides changes in financial assets and liabilities that are measured at fair value based on Level 3 inputs:

Unrealized gains (losses)

Included in earnings

Included in other comprehensive income

Purchases, sales or other settlements during the period

Net transfers in to (out of) Level 3

The table below reflects the gross and net fair values of the Corporation’s derivative instruments as of December 31, 2009:

Derivative contracts designated as hedging instruments

Commodity

Derivative contracts not designated as hedging instruments*

Total derivative contracts not designated as hedging instruments

Gross fair value of derivative contracts

Master netting arrangements

Cash collateral (received) posted

Net fair value of derivative contracts

The Corporation generally enters into master netting arrangements to mitigate counterparty credit risk. Master netting arrangements are standardized contracts that govern all specified transactions with the same counterparty and allow the Corporation to terminate all contracts upon occurrence of certain events, such as a counterparty’s default or bankruptcy. Where these arrangements provide the right of offset and the Corporation’s intent and practice is to offset amounts in the case of contract terminations, the Corporation records fair value on a net basis.

The carrying amounts of the Corporation’s financial instruments and derivatives are recorded at their fair values at December 31, 2009 and 2008, while fixed rate long-term debt is recorded at a carrying value of $4,467 million (fair value of $5,073 million) at December 31, 2009 and a carrying value of $3,103 million (fair value of $3,031 million) at December 31, 2008.

Credit Risk: The Corporation is exposed to credit risks that may at times be concentrated with certain counterparties or groups of counterparties. Accounts receivable are generated from a diverse domestic and international customer base. The Corporation’s net receivables at December 31, 2009 are concentrated with counterparties as follows: oil and gas companies — 14%, US government entities — 13%, manufacturers — 12% and domestic and foreign trading companies — 11%. The Corporation reduces its risk related to certain counterparties by using master netting arrangements and requiring collateral, generally cash or letters of credit. The Corporation records the cash collateral received or posted as an offset of the fair value of derivatives executed with the same counterparty. At December 31, 2009 and 2008, the Corporation is holding cash from counterparties of approximately $317 million and $705 million, respectively. The Corporation has posted cash to counterparties at December 31, 2009 and 2008 of approximately $269 million and $394 million, respectively.

At December 31, 2009, the Corporation had a total of $2,847 million of outstanding letters of credit, primarily issued to satisfy margin requirements. Certain of the Corporation’s agreements also contain contingent collateral provisions that could require the Corporation to post additional collateral if the Corporation’s credit rating declines. As of December 31, 2009, the net liability related to derivatives with contingent collateral provisions was approximately $2,120 million before cash collateral posted of approximately $260 million. At December 31, 2009, all three major credit rating agencies that rate the Corporation’s debt had assigned an investment grade rating. If two of the three agencies were to downgrade the Corporation’s rating to below investment grade, as of December 31, 2009, the Corporation would be required to post additional collateral of approximately $281 million.

At December 31, 2009, the Corporation’s guarantees include $121 million of HOVENSA’s crude oil purchases and $15 million of HOVENSA’s senior debt obligations. In addition, the Corporation has $100 million in letters of credit for which it is contingently liable. As a result, the maximum potential amount of future payments that the Corporation could be required to make under its guarantees is $236 million at December 31, 2009 ($219 million at December 31, 2008). The Corporation also has a contingent purchase obligation expiring in April 2012, to acquire the remaining interest in WilcoHess, a retail gasoline station joint venture. As of December 31, 2009, the estimated value of the purchase obligation is approximately $184 million.

The Corporation is subject to loss contingencies with respect to various lawsuits, claims and other proceedings, including environmental matters. A liability is recognized in the Corporation’s consolidated financial statements when it is probable a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, the Corporation discloses the nature of those contingencies.

The United States Deep Water Royalty Relief Act of 1995 (the Act) implemented a royalty relief program that relieves eligible leases issued between November 28, 1995 and November 28, 2000 from paying royalties on deepwater production in Federal Outer Continental Shelf lands. The Act does not impose any price thresholds in order to qualify for the royalty relief. The U.S. Minerals Management Service (MMS) created regulations that included pricing requirements to qualify for the royalty relief provided in the Act. During the period from 2003 to

2009, the Corporation accrued the royalties imposed by the MMS regulations. The legality of the thresholds imposed by the MMS was challenged in the federal courts and, in October 2009, the U.S. Supreme Court decided not to review the appellate court’s decision against the MMS. As a result, the Corporation recognized a pre-tax gain of $143 million ($89 million after income taxes) in 2009 to reverse all previously recorded royalties. The pre-tax gain is reported in Other, net within the Statement of Consolidated Income.

The Corporation is also currently subject to certain other existing claims, lawsuits and proceedings, which it considers routine and incidental to its business. The Corporation believes that there is only a remote likelihood that future costs related to any of these other known contingent liability exposures would have a material adverse impact on its financial position or results of operations.

The Corporation has two operating segments that comprise the structure used by senior management to make key operating decisions and assess performance. These are (1) Exploration and Production and (2) Marketing and Refining. The Exploration and Production segment explores for, develops, produces, purchases, transports and sells crude oil and natural gas. The Marketing and Refining segment manufactures refined petroleum products and purchases, trades and markets refined petroleum products, natural gas and electricity.

The following table presents financial data by operating segment for each of the three years ended December 31, 2009:

Operating revenues

Total operating revenues(b)

Less: Transfers between affiliates

Operating revenues from unaffiliated customers

Net income (loss) attributable to Hess Corporation

Equity in income (loss) of HOVENSA L.L.C.

Depreciation, depletion and amortization

Provision (benefit) for income taxes

Investments in affiliates

Identifiable assets

Capital employed(c)

Capital expenditures

Equity in income of HOVENSA L.L.C.

Financial information by major geographic area for each of the three years ended December 31, 2009:

Operating revenues

Property, plant and equipment (net)

The following table presents related party transactions for the year-ended December 31:

Purchases of petroleum products:

HOVENSA*

Sales of petroleum products and crude oil:

WilcoHess

HOVENSA

(Unaudited)

The Supplementary Oil and Gas Data that follows is presented in accordance with ASC 932, Disclosures about Oil and Gas Producing Activities, and includes (1) costs incurred, capitalized costs and results of operations relating to oil and gas producing activities, (2) net proved oil and gas reserves, and (3) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves, including a reconciliation of changes therein.

The Corporation produces crude oil, natural gas liquids and/or natural gas principally in Algeria, Azerbaijan, Denmark, Equatorial Guinea, Gabon, Indonesia, Libya, Malaysia, Norway, Russia, Thailand, the United Kingdom and the United States. Exploration activities are also conducted, or are planned, in additional countries.

Costs Incurred in Oil and Gas Producing Activities

For the Years Ended December 31

Property acquisitions

Unproved

Proved*

Exploration

Production and development capital expenditures**

Capitalized Costs Relating to Oil and Gas Producing Activities

Unproved properties

Proved properties

Wells, equipment and related facilities

Total costs

Less: reserve for depreciation, depletion, amortization and lease impairment

Net capitalized costs

Results of Operations for Oil and Gas Producing Activities

The results of operations shown below exclude non-oil and gas producing activities, primarily gains on sales of oil and gas properties, interest expense, gains and losses resulting from foreign exchange transactions and other non-operating income. Therefore, these results are on a different basis than the net income from Exploration and Production operations reported in management’s discussion and analysis of results of operations and in Note 16, Segment Information, in the notes to the financial statements.

Unaffiliated customers

Inter-company

Total revenues

Production expenses, including related taxes(a)

Depreciation, depletion and amortization(b)

Results of operations before income taxes

Results of operations

Production expenses, including related taxes(c)

Depreciation, depletion and amortization(d)

Depreciation, depletion and amortization(e)

Oil and Gas Reserves

The Corporation’s proved oil and gas reserves are calculated in accordance with SEC regulations and the requirements of the FASB. Proved oil and gas reserves are quantities, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. The Corporation’s estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed by internal teams of geoscience professionals and reservoir engineers. Estimates of reserves were prepared by the use of standard engineering and geoscience methods generally accepted in the petroleum industry. The method or combination of methods used in the analysis of each reservoir is based on the maturity of the reservoir, the completeness of the subsurface data available at the time of the estimate, the stage of reservoir development and the production history. Where applicable, reliable technologies may be used in reserve estimation, as defined in the SEC regulations. These technologies, including computational methods, must have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Commencing in 2009, the product prices used in the estimation of oil and gas reserves were the average oil and gas selling prices during the twelve month period prior to the reporting date determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, except for prices set in contractual arrangements. In order for reserves to be classified as proved, any required government approvals must be obtained and depending on the cost of the project, either senior management or the board of directors must commit to fund the development.

The Corporation’s proved reserves are subject to certain risks and uncertainties. These risks include commodity price risk, technical risk and political risk. Reference is made to Item 1A, Risk Factors Related to Our Business and Operations on page 11 of this Form 10-K.

Internal Controls

The Corporation maintains internal controls over its oil and gas reserve estimation process which are administered by the Corporation’s Senior Vice President of E&P Technology and its Chief Financial Officer. Estimates of reserves are prepared by technical staff that work directly with the oil and gas properties using standard reserve estimation guidelines, definitions and methodologies. Each year, reserve estimates for a selection of the Corporation’s assets are subject to internal technical audits and reviews. In addition, an independent third party reserve engineer reviews and audits a significant portion of the Corporation’s reported reserves (see below). Reserve estimates are reviewed by senior management and the Board of Directors.

Qualifications

The person primarily responsible for overseeing the preparation of the Corporation’s oil and gas reserves is Mr. Scott Heck, Senior Vice President of E&P Technology. Mr. Heck is a member of the Society of Petroleum Engineers with 30 years of industry experience in oil and gas reservoir management and reserve estimation.

Reserves Audit

The Corporation engaged the consulting firm of DeGolyer and MacNaughton (D&M) to perform an audit of the internally prepared reserve estimates on certain fields aggregating approximately 80% of 2009 year-end reported reserve quantities on a barrel of oil equivalent basis. The purpose of the report dated January 15, 2010 was to provide additional assurance on the reasonableness of internally prepared reserve estimates and compliance with SEC regulations. The D&M letter report on the Corporation’s estimated oil and gas reserves was prepared using standard geological and engineering methods generally accepted in the petroleum industry. D&M is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. The D&M letter report on the Corporation’s December 31, 2009 oil and gas reserves is included as an exhibit to this Form 10-K. While the D&M report should be read in its entirety, the report concludes that for the properties reviewed by D&M, the total net proved reserve estimates prepared by Hess and audited by D&M, in the aggregate, did not differ materially. The report also includes among other information, the qualifications of the technical person primarily responsible for overseeing such reserve audit.

Effect of adopting new SEC requirements

The SEC issued a final rule on oil and gas reserve estimation and disclosure effective for year-end 2009 reporting. The SEC’s final rule was designed to modernize and update the oil and gas reserve disclosure requirements to align them with current industry practices and changes in technology. In January 2010, the FASB issued its final accounting standards update, Extractive Industries — Oil and Gas (ASC 932), which principally conformed existing FASB standards to the new SEC guidelines. Since it was not practical to calculate reserve estimates under both the old and new reserve estimation standards as of year end, it is not possible to precisely measure the effect of adopting the new SEC requirements on total proved reserves at December 31, 2009. However, the Corporation estimates that the effect of initially applying the new rules, primarily due to application of the new reserve definitions and the consideration of permitted technology, was to increase year end 2009 total proved reserves by approximately 2%. The change in reserve estimates resulting from applying the new rules is included in the table below as 2009 revisions and additions to proved reserves. The Corporation estimates that the effect of adopting the new rules on its net income in 2010 will be an increase of approximately $80 million, after tax, due to lower depreciation, depletion and amortization costs, assuming 2010 budgeted production levels for the affected fields occur as forecasted.

Proved undeveloped reserves

The December 31, 2009 oil and gas reserve estimates disclosed below include 374 million barrels of liquid hydrocarbons and 1,276 million mcf of natural gas classified as proved undeveloped reserves. Proved undeveloped liquid reserves decreased in 2009, primarily due to the commencement of production from the Shenzi Field in the deepwater Gulf of Mexico. Proved undeveloped natural gas reserves also decreased in 2009 due to the continuation of development activities in Block A-18 in the JDA. In addition, as part of its normal production operations, the

Corporation’s drilling programs on existing fields resulted in the reclassification of proved undeveloped reserves to developed. In 2009, these changes occurred primarily at certain fields in the United States, Equatorial Guinea, Azerbaijan and Russia. For the year ended December 31, 2009, the Corporation estimates that capital expenditures of approximately $450 million were incurred to convert proved undeveloped reserves to proved developed reserves. The Corporation is involved in multiple long term projects that have staged developments. Certain of these projects have proved reserves, which have been classified as undeveloped for a period in excess of five years, totaling approximately 145 million barrels of oil equivalent, or 10% of year end 2009 total proved reserves. The proved undeveloped reserves in excess of five years are related to gas projects in Block A-18 in the JDA, Indonesia, and Norway that are being developed in phases to satisfy long-term gas sales contracts and an oil project in Azerbaijan that is still under development.

Following are the Corporation’s proved reserves for the three years ended December 31, 2009:

Total

Net Proved Developed and Undeveloped Reserves

At January 1, 2007

Revisions of previous estimates(b)

Extensions, discoveries and other additions

Improved recovery

Purchases of minerals in place

Sales of minerals in place

Production

At December 31, 2007(a)

At December 31, 2008(a)

At December 31, 2009

Net Proved Developed Reserves

At December 31, 2007

At December 31, 2008

Net Proved Undeveloped Reserves

Production sharing contracts

The Corporation’s proved reserves include crude oil and natural gas reserves relating to long-term supply agreements with governments or authorities in which the Corporation has the legal right to produce or has a revenue interest in the production. Proved reserves from these production sharing contracts for each of the three years ended December 31, 2009 are presented separately below, as well as volumes produced and received during 2009, 2008 and 2007 from these production sharing contracts.

Production Sharing Contracts

Proved Reserves

Production

2007

2008

2009

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Future net cash flows are calculated by applying prescribed oil and gas selling prices used in determining year-end reserve estimates (adjusted for price changes provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future development and production costs, which are based on year-end costs and existing economic assumptions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the pre-tax net cash flows relating to the Corporation’s proved oil and gas reserves. Future net cash flows are discounted at the prescribed rate of 10%. The discounted future net cash flow estimates do not include exploration expenses, interest expense or corporate general and administrative expenses. The selling prices of crude oil and natural gas are highly volatile. The prices which are required to be used for the

discounted future net cash flows do not include the effects of hedges and may not be representative of future selling prices. The future net cash flow estimates could be materially different if other assumptions were used.

At December 31

Future revenues

Less:

Future production costs

Future development costs

Future income tax expenses

Future net cash flows

Less: discount at 10% annual rate

Standardized measure of discounted future net cash flows

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Standardized measure of discounted future net cash flows at beginning of year

Changes during the year

Sales and transfers of oil and gas produced during year, net of production costs

Development costs incurred during year

Net changes in prices and production costs applicable to future production

Net change in estimated future development costs

Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs

Revisions of previous oil and gas reserve estimates

Net purchases (sales) of minerals in place, before income taxes

Accretion of discount

Net change in income taxes

Revision in rate or timing of future production and other changes

Standardized measure of discounted future net cash flows at end of year

Quarterly results of operations for the years ended December 31:

First

Second

Third

Fourth

The results of operations for the periods reported herein should not be considered as indicative of future operating results.

None.

Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2009, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of December 31, 2009.

There was no change in internal controls over financial reporting identified in the evaluation required by paragraph (d) of Rules 13a-15 or 15d-15 in the quarter ended December 31, 2009 that has materially affected, or is reasonably likely to materially affect, internal controls over financial reporting.

Management’s report on internal control over financial reporting and the attestation report on the Corporation’s internal controls over financial reporting are included in Item 8 of this annual report on Form 10-K.

Information relating to Directors is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2010.

Information regarding executive officers is included in Part I hereof.

The Corporation has adopted a Code of Business Conduct and Ethics applicable to the Corporation’s directors, officers (including the Corporation’s principal executive officer and principal financial officer) and employees. The Code of Business Conduct and Ethics is available on the Corporation’s website. In the event that we amend or waive any of the provisions of the Code of Business Conduct and Ethics that relate to any element of the code of ethics definition enumerated in Item 406(b) of Regulation S-K, we intend to disclose the same on the Corporation’s website at www.hess.com.

Information relating to the audit committee is incorporated herein by reference to “Election of Directors” from the registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2010.

Information relating to executive compensation is incorporated herein by reference to “Election of Directors — Executive Compensation and Other Information,” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2010.

Information pertaining to security ownership of certain beneficial owners and management is incorporated herein by reference to “Election of Directors — Ownership of Voting Securities by Certain Beneficial Owners” and “Election of Directors — Ownership of Equity Securities by Management” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2010.

See Equity Compensation Plans in Item 5 for information pertaining to securities authorized for issuance under equity compensation plans.

Information relating to this item is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2010.

Information relating to this item is incorporated by reference to “Ratification of Selection of Independent Auditors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2010.

The financial statements filed as part of this Annual Report on Form 10-K are listed in the accompanying index to financial statements and schedules in Item 8, Financial Statements and Supplementary Data.


4(9)		Form of 6.00% Note, incorporated by reference to Exhibit 4.1 to the Form 8-K filed on December 15, 2009. Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.
10(1)		Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(4) of Form 10-Q of Registrant for the three months ended June 30, 1981.
10(2)		Restated Second Extension and Amendment Agreement dated July 27, 1990 between Hess Oil Virgin Islands Corp. and the Government of the Virgin Islands incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1990.
10(3)		Technical Clarifying Amendment dated as of November 17, 1993 to Restated Second Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1993.
10(4)		Third Extension and Amendment Agreement dated April 15, 1998 and effective October 30, 1998 among Hess Oil Virgin Islands Corp., PDVSA V.I., Inc., HOVENSA L.L.C. and the Government of the Virgin Islands incorporated by reference to Exhibit 10(4) of Form 10-K of Registrant for the fiscal year ended December 31, 1998.
10(5)	*	Incentive Cash Bonus Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on February 10, 2009.
10(6)	*	Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(7)	*	Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for fiscal year ended December 31, 2006.
10(8)	*	Performance Incentive Plan for Senior Officers, incorporated by reference to Exhibit (10) of Form 10-Q of Registrant for the three months ended June 30, 2006.
10(9)	*	Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.
10(10)	*	Amendment dated December 31, 2006 to Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(10) of Form 10-K of Registrant for fiscal year ended December 31, 2006.
10(11)	*	Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(12)	*	Second Amended and Restated 1995 Long-Term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(13)	*	2008 Long Term Incentive Plan, incorporated by reference to Annex B to Registrant’s definitive proxy statement filed on March 27, 2008.
10(14)	*	Forms of Awards under Registrant’s 2008 Long Term Incentive Plan.
10(15)	*	Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant dated January 1, 2007.
10(16)	*	Amended and Restated Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and F. Borden Walker, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended June 30, 2009. A substantially identical agreement (differing only in the signatories thereto) was entered into between Registrant and John B. Hess.
10(17)	*	Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and John P. Rielly. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (including the named executive officers, other than those referred to in Exhibit 10(15)).

During the three months ended December 31, 2009, Registrant filed or furnished the following report on Form 8-K:

1. Filing dated October 29, 2009 reporting under Items 2.02 and 9.01, a news release dated October 29, 2009 reporting results for the third quarter of 2009.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th day of February 2010.

HESS CORPORATION
(Registrant)

/s/ John P. Rielly

(John P. Rielly)

Senior Vice President and

Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature

Title

Date

/s/ John B. Hess

/s/ Samuel W. Bodman

/s/ Nicholas F. Brady

/s/ Gregory P. Hill

/s/ Edith E. Holiday

/s/ Thomas H. Kean

/s/ Risa Lavizzo-Mourey

/s/ Craig G. Matthews

/s/ John H. Mullin

/s/ Frank A. Olson

/s/ John P. Rielly

/s/ Ernst H. von Metzsch

/s/ F. Borden Walker

/s/ Robert N. Wilson

VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2009, 2008 and 2007

Description

Losses on receivables

EXHIBIT INDEX


10(5)	*	Incentive Cash Bonus Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on February 10, 2009.
10(6)	*	Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(7)	*	Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for fiscal year ended December 31, 2006.
10(8)	*	Performance Incentive Plan for Senior Officers, incorporated by reference to Exhibit (10) of Form 10-Q of Registrant for the three months ended June 30, 2006.
10(9)	*	Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.
10(10)	*	Amendment dated December 31, 2006 to Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(10) of Form 10-K of Registrant for fiscal year ended December 31, 2006.
10(11)	*	Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(12)	*	Second Amended and Restated 1995 Long-Term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(13)	*	2008 Long Term Incentive Plan, incorporated by reference to Annex B to Registrant’s definitive proxy statement filed on March 27, 2008.
10(14)	*	Forms of Awards under Registrant’s 2008 Long Term Incentive Plan.
10(15)	*	Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant dated January 1, 2007.
10(16)	*	Amended and Restated Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and F. Borden Walker, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended June 30, 2009. A substantially identical agreement (differing only in the signatories thereto) was entered into between Registrant and John B. Hess.
10(17)	*	Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and John P. Rielly. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (including the named executive officers, other than those referred to in Exhibit 10(15)).
10(18)	*	Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
10(19)	*	Agreement between Registrant and Gregory P. Hill relating to his compensation and other terms of employment, incorporated by reference to Form 8-K of Registrant filed January 7, 2009.
10(20)	*	Agreement between Registrant and Timothy B. Goodell relating to his compensation and other terms of employment.
10(21)	*	Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.
10(22)		Asset Purchase and Contribution Agreement dated as of October 26, 1998, among PDVSA V.I., Inc., Hess Oil Virgin Islands Corp. and HOVENSA L.L.C. (including Glossary of definitions) incorporated by reference to Exhibit 2.1 of Form 8-K of Registrant dated October 30, 1998.
10(23)		Amended and Restated Limited Liability Company Agreement of HOVENSA L.L.C. dated as of October 30, 1998 incorporated by reference to Exhibit 10.1 of Form 8-K of Registrant dated October 30, 1998.
21		Subsidiaries of Registrant.
23(1)		Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 26, 2010.
23(2)		Consent of DeGolyer and MacNaughton dated February 26, 2010.
31(1)		Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).

Business description of HESS-CORPORATION from last 10-k form