Edgar Filing: HESS CORP

Large accelerated filer þ

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

Form 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
		OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2011
		or
¨		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
		OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

		Commission File Number 1-1204

Hess Corporation

(Exact name of Registrant as specified in its charter)


DELAWARE		13-4921002
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
1185 AVENUE OF THE AMERICAS, NEW YORK, N.Y.		10036 (Zip Code)
(Address of principal executive offices)

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

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


Title of Each Class		Name of Each Exchange on Which Registered
Common Stock (par value $1.00)		New York Stock Exchange

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 ¨

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 ¨ 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 ¨

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 ¨

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):

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

The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $22,545,000,000 computed using the outstanding common shares and closing market price on June 30, 2011.

At December 31, 2011, there were 339,975,610 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 2, 2012.

HESS CORPORATION

Form 10-K

TABLE OF CONTENTS


Item No.		Page
	PART I
1 and 2.	Business and Properties		2
1A.	Risk Factors Related to Our Business and Operations		14
3.	Legal Proceedings		16

	PART II
5.	Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities		18
6.	Selected Financial Data		20
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
7A.	Quantitative and Qualitative Disclosures About Market Risk		40
8.	Financial Statements and Supplementary Data		43
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		95
9A.	Controls and Procedures		95
9B.	Other Information		95

	PART III
10.	Directors, Executive Officers and Corporate Governance		95
11.	Executive Compensation		96
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		96
13.	Certain Relationships and Related Transactions, and Director Independence		96
14.	Principal Accounting Fees and Services		96

	PART IV
15.	Exhibits, Financial Statement Schedules		97
	Signatures		101
	Financial Statements of HOVENSA L.L.C. as of December 31, 2011		103

PART I

Items 1 and 2. Business and Properties

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, Brunei, China, Denmark, Egypt, Equatorial Guinea, France, Ghana, Indonesia, the Kurdistan region of Iraq, Libya, Malaysia, Norway, Peru, Russia, Thailand, the United Kingdom and the United States (U.S.). 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 HOVENSA L.L.C. (HOVENSA), a joint venture in the U.S. Virgin Islands. In January 2012, HOVENSA announced a decision to shut down its refinery and operate the complex as an oil storage terminal. The Corporation also operates a refining facility, terminals, and retail gasoline stations, most of which include convenience stores, that 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:


	Crude Oil, Condensate & Natural Gas Liquids (c)				Natural Gas				Total Barrels of Oil Equivalent (BOE) (a)
	2011		2010		2011		2010		2011		2010
	(Millions of barrels)				(Millions of mcf)				(Millions of barrels)

Developed
United States		190		180		199		199		223		213
Europe (b)		212		210		273		424		258		281
Africa		194		215		63		54		204		224
Asia		25		22		677		638		138		128

		621		627		1,212		1,315		823		846


Undeveloped
United States		183		124		161		81		210		138
Europe (b)		282		256		290		295		331		305
Africa		56		55		8		9		57		56
Asia		27		42		752		898		152		192

		548		477		1,211		1,283		750		691


Total
United States		373		304		360		280		433		351
Europe (b)		494		466		563		719		589		586
Africa		250		270		71		63		261		280
Asia		52		64		1,429		1,536		290		320

		1,169		1,104		2,423		2,598		1,573		1,537

(a)

Reflects natural gas reserves converted on the basis of relative energy content of six mcf equals one barrel of oil equivalent (one mcf represents one thousand cubic feet). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. See the average selling prices in the table on page 8.

(b)

Proved reserves in Norway, which represented 23% and 22% of the Corporation’s total reserves at December 31, 2011 and 2010, respectively, were as follows:

Crude Oil, Condensate &
Natural Gas Liquids

Natural Gas

Total Barrels of Oil
Equivalent (BOE)

2011

2010

2011

2010

2011

2010

(Millions of barrels)

(Millions of mcf)

(Millions of barrels)

Developed

108

137

157

131

123

Undeveloped

185

167

251

247

227

208

Total

293

264

388

404

358

331

(c)

Total natural gas liquids reserves were 113 million barrels (56 million barrels developed and 57 million barrels undeveloped) at December 31, 2011 and 102 million barrels (54 million barrels developed and 48 million barrels undeveloped) at December 31, 2010.

On a barrel of oil equivalent (boe) basis, 48% of the Corporation’s worldwide proved reserves were undeveloped at December 31, 2011 (45% at December 31, 2010). Proved reserves held under production sharing contracts at December 31, 2011 totaled 12% of crude oil and natural gas liquids reserves and 51% of natural gas reserves, compared with 15% of crude oil and natural gas liquids reserves and 51% of natural gas reserves at December 31, 2010. See the Supplementary Oil and Gas Data on pages 85 through 93 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:


	2011		2010		2009
Crude oil (thousands of barrels per day)
United States
Offshore		44		52		39
Onshore		37		23		21

		81		75		60

Europe
Russia		45		42		37
Norway*		20		16		13
United Kingdom		14		19		21
Denmark		10		11		12

		89		88		83

Africa
Equatorial Guinea		54		69		70
Libya		4		23		22
Algeria		8		11		14
Gabon		—		10		14

		66		113		120

Asia
Azerbaijan		6		7		8
Other		7		6		8

		13		13		16

Total		249		289		279

Natural gas liquids (thousands of barrels per day)
United States
Offshore		6		7		4
Onshore		7		7		7

		13		14		11

Europe*		3		3		3

Asia		1		1		—

Total		17		18		14


	2011		2010		2009
Natural gas (thousands of mcf per day)
United States
Offshore		61		70		55
Onshore		39		38		38

		100		108		93

Europe
Norway*		29		29		21
United Kingdom		41		93		118
Denmark		11		12		12

		81		134		151

Asia and Other
Joint Development Area of Malaysia/Thailand (JDA)		267		282		294
Thailand		84		85		85
Indonesia		56		50		65
Other		35		10		2

		442		427		446

Total		623		669		690

Barrels of oil equivalent (per day)**		370		418		408

Norway production for 2011 included 18 thousand barrels per day of crude oil, 1 thousand barrels per day of natural gas liquids and 15 thousand mcf per day of natural gas from the Valhall Field. Norway production for 2010 included 14 thousand barrels per day of crude oil, 1 thousand barrels per day of natural gas liquids and 13 thousand mcf per day of natural gas from the Valhall Field.

Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. See the average selling prices in the table on page 8.

A description of our significant E&P operations is as follows:

United States

At December 31, 2011, 28% of the Corporation’s total proved reserves were located in the United States. During 2011, 35% of the Corporation’s crude oil and natural gas liquids production and 16% of its natural gas production were from United States operations. The Corporation’s production in the United States was from offshore properties in the Gulf of Mexico, as well as onshore properties principally in the Williston Basin of North Dakota and in the Permian Basin of Texas.

Offshore: The Corporation’s production offshore the United States was principally from the Shenzi (Hess 28%), Llano (Hess 50%), Conger (Hess 38%), Baldpate (Hess 50%), Hack Wilson (Hess 25%) and Penn State (Hess 50%) fields.

At the Shenzi Field, the operator is expected to complete initial installation of water injection equipment and drill additional development wells in 2012. At the outside operated Llano Field, a workover on a shut-in well, which was producing in excess of 10,000 net barrels of oil equivalent per day prior to shut-in, will be completed in 2012. Additional development drilling at the Llano Field is planned to commence during the second half of 2012.

During the third quarter of 2011, the Corporation, as operator, and its partner sanctioned the development of the Tubular Bells Field (Hess 57%) in the Mississippi Canyon Block 725 Area in the deepwater Gulf of Mexico. In 2012, field development will be advanced with the on-going construction of a floating production system and development drilling that is scheduled to start in the second quarter. First production is anticipated in 2014.

At the Pony prospect on Green Canyon Block 468 (Hess 100%), the Corporation has signed a non-binding agreement with the owners of the adjacent Knotty Head prospect on Green Canyon Block 512 that outlines a proposal to jointly develop the field. This agreement provides that the Corporation will be operator of the joint development. Negotiation of a joint operating agreement, including working interest percentages for the partners, and planning for the field development are progressing. The project is now targeted for sanction in 2013.

At December 31, 2011, the Corporation had interests in 289 blocks in the Gulf of Mexico, of which 267 were exploration blocks comprising 1,054,000 net undeveloped acres, with an additional 46,000 net acres held for production and development operations.

Onshore: In North Dakota, the Corporation holds nearly 900,000 net acres in the Bakken oil shale play (Bakken). In 2012, the Corporation plans to invest approximately $1.9 billion for drilling and infrastructure in the Bakken. The Corporation plans to operate 16 rigs with five dedicated hydraulic fracturing crews in 2012. Infrastructure investments include completion of a crude oil rail loading and storage facility, which is due to become fully operational in the first quarter of 2012, and continuing expansion of the Tioga gas plant.

In Texas, the Corporation holds a 34% interest in the Seminole-San Andres Unit and is operator. The Corporation also holds more than 100,000 net acres in the Eagle Ford shale. First production from the Eagle Ford commenced in May 2011. During 2012, the Corporation plans to operate three rigs and drill approximately 25 to 30 wells.

In 2011, the Corporation entered into agreements to acquire approximately 85,000 net acres in the Utica Shale play in eastern Ohio for approximately $750 million, principally through the acquisition of Marquette Exploration, LLC. The Corporation also completed the acquisition of a 50% undivided interest in CONSOL Energy Inc.’s (CONSOL) nearly 200,000 acres in the Utica Shale play for $59 million in cash at closing and the agreement to fund 50% of CONSOL’s share of the drilling costs up to $534 million within a 5-year period. Appraisal of the Utica acreage commenced in the fourth quarter of 2011 and will continue during 2012 with the acquisition of seismic and the planned drilling of 29 wells.

Europe

At December 31, 2011, 37% of the Corporation’s total proved reserves were located in Europe (Norway 23%, United Kingdom 4%, Denmark 3% and Russia 7%). During 2011, 35% of the Corporation’s crude oil and natural gas liquids production and 13% of its natural gas production were from European operations.

Norway: Substantially all of the 2011 Norwegian production was from the Corporation’s interests in the Valhall Field (Hess 64%). At December 31, 2011, the Corporation also held interests in the Hod (Hess 63%) and Snohvit (Hess 3%) fields. All three of the Corporation’s Norwegian field interests are located offshore.

At the Valhall Field, a multi-year redevelopment project is scheduled to be completed in 2012. The project includes the installation of two new platforms with production, compression and water injection equipment and living quarters. In addition, further drilling is planned for Valhall in 2012. In the third quarter of 2012, there is expected to be significant downtime for the operator to complete the project and commission the new facilities.

In August 2011, the Corporation completed the sale of its interests in the Snorre Field (Hess 1%), offshore Norway. In January 2012, the Corporation completed the sale of its interests in the Snohvit Field.

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 Bittern (Hess 28%), Nevis (Hess 27%), Beryl (Hess 22%) and Schiehallion (Hess 16%) fields. Natural gas production from the United Kingdom was primarily from the Nevis (Hess 27%) and Beryl (Hess 22%) fields. The Corporation also has interests in the Atlantic (Hess 25%), Cromarty (Hess 90%), Fife, Flora and Angus (Hess 85%), Fergus (Hess 65%), Ivanhoe and Rob Roy (Hess 77%), Renee (Hess 14%) and Rubie (Hess 19%) fields. These fields are no longer producing and decommissioning activities have commenced.

In the first half of 2011, the Corporation completed the sale of a package of natural gas producing assets including its interests in the Easington Catchment Area (Hess 30%), the Bacton Area (Hess 23%), the Everest Field (Hess 19%) and the Lomond Field (Hess 17%), as well as its interest in the Central Area Transmission System pipeline. The Corporation also completed the sale of its interest in the Cook Field (Hess 28%) in August 2011.

Denmark: Crude oil and natural gas production comes from the Corporation’s operated interest in the South Arne Field (Hess 62%), offshore Denmark. In October 2011, the Corporation acquired an additional 4% interest in the South Arne Field increasing its interest to 62% from 58%.

Russia: The Corporation’s activities in Russia are conducted through its interest in a subsidiary operating in the Volga-Urals region. In the third quarter of 2011, the Corporation acquired an additional 5% interest in its

subsidiary, increasing its ownership to 90%. As of December 31, 2011, this subsidiary had exploration and production rights in 22 license areas. During 2012, the Corporation plans to continue drilling and to install gas treatment facilities that are anticipated to start up in the fourth quarter of 2012.

France: The Corporation’s activities in France are conducted through an agreement with Toreador Resources Corporation (Toreador), under which it can invest in an initial exploration phase and earn up to a 50% working interest in, and become operator of, Toreador’s approximately 680,000 net acres in the Paris Basin. An initial six exploration well program, which was scheduled to begin in 2011, was deferred due to a temporary drilling moratorium requested by the government prior to the implementation of a law prohibiting hydraulic fracturing. In 2012, the Corporation anticipates drilling up to three conventional vertical wells and continuing geological and geophysical analysis.

Africa

At December 31, 2011, 17% of the Corporation’s total proved reserves were located in Africa (Equatorial Guinea 5%, Algeria 1% and Libya 11%). During 2011, 25% of the Corporation’s crude oil and natural gas liquids production was from its African operations.

Equatorial Guinea: The Corporation is operator and owns an interest in Block G (Hess 85%) which contains the Ceiba Field and Okume Complex. During 2012, the Corporation intends to drill additional production wells at the Ceiba Field. Additional development drilling at the Okume Complex is planned to commence during 2013.

Algeria: The Corporation has a 49% interest in a venture with the Algerian national oil company that redeveloped three oil fields. The Corporation also has an interest in Bir El Msana (BMS) Block 401C (Hess 45%). In 2011, the Corporation sanctioned a small development project at the BMS Field.

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 two wells discovered hydrocarbons.

In response to civil unrest in Libya, a number of measures were taken by the international community in the first quarter of 2011, including the imposition of economic sanctions. Production at the Waha Field was suspended in the first quarter of 2011. As a consequence of the civil unrest and the sanctions, the Corporation delivered force majeure notices to the Libyan government relating to the agreements covering its exploration and production interests in order to protect its rights while it was temporarily prevented from fulfilling its obligations and benefiting from the rights granted by those agreements. Production at the Waha Field restarted during the fourth quarter of 2011 at levels that were significantly lower than those prior to the civil unrest. The Corporation’s Libyan production averaged 23,000 barrels of oil equivalent per day (boepd) for the full year of 2010 and 4,000 boepd for 2011. The force majeure covering the Corporation’s production interests was withdrawn at the end of the fourth quarter of 2011, as the economic sanctions were lifted. The force majeure covering the Corporation’s offshore exploration interests remained in place at year-end but is expected to be withdrawn in 2012. The Corporation had proved reserves of 166 million barrels of oil equivalent in Libya at December 31, 2011. At December 31, 2011, the net book value of the Corporation’s exploration and production assets in Libya was approximately $500 million.

Ghana: The Corporation holds a 90% interest and is operator in the Deepwater Tano Cape Three Points License where the Corporation drilled an exploration well in 2011 that encountered an estimated 490 net feet of oil and gas condensate pay over three separate intervals. The Corporation anticipates commencing additional exploration drilling in the first quarter of 2012, subject to government approvals and rig availability.

Egypt: The Corporation owns an 80% interest in Block 1 offshore Egypt in the North Red Sea.

Asia

At December 31, 2011, 18% of the Corporation’s total proved reserves were located in the Asia region (JDA 8%, Indonesia 5%, Thailand 3%, Azerbaijan 1% and Malaysia 1%). During 2011, 5% of the Corporation’s crude oil and natural gas liquids production and 71% of its natural gas production were from its Asian 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. In 2011, the operator continued development drilling and

wellhead platform construction and installation activities. In 2012, the operator will continue development of the block by progressing wellhead platform installations and with the anticipated sanction of a compression project.

Malaysia: The Corporation’s production in Malaysia comes from its interest in Block PM301 (Hess 50%), which is adjacent to Block A-18 of the JDA where the natural gas is processed. The Corporation also owns interests in Block PM302 (Hess 50%) and Block SB302 (Hess 40%). Technical and commercial evaluations are underway to assess the development alternatives for these blocks.

Indonesia: The Corporation’s production in Indonesia comes from its interests offshore in the Ujung Pangkah project (Hess 75%), and the Natuna A Field (Hess 23%). During 2011, a second wellhead platform and central processing facility were installed at Ujung Pangkah. At the Natuna A Field, the operator completed construction and installed a second wellhead platform and a central processing platform. The Corporation holds a 100% working interest in the offshore Semai V Block, where it drilled two exploration wells during 2011 which were both expensed in the fourth quarter. The Corporation also owns a 100% working interest in the offshore South Sesulu Block, a 49% interest in the West Timor Block, which includes onshore and offshore acreage, and a 100% interest in the Timor Sea Block 1, offshore Indonesia.

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

Azerbaijan: The Corporation has an interest in the Azeri-Chirag-Guneshli (ACG) fields (Hess 3%) in the Caspian Sea and also owns an interest in the Baku-Tbilisi-Ceyhan oil transportation pipeline company (Hess 2%).

Brunei: The Corporation has an interest in Block CA-1 (Hess 14%). In 2011, the operator drilled the Julong Center exploration well which was subsequently expensed. The operator anticipates commencing further exploration drilling on this block in 2012.

Kurdistan Region of Iraq: In July 2011, the Corporation signed production sharing contracts with the Kurdistan Regional Government of Iraq for the Dinarta and Shakrok exploration blocks. The Corporation is operator and has an 80% paying interest (64% participating interest) in the blocks, which have a combined area of more than 670 square miles. The terms of the contracts require the acquisition of 2D seismic and drilling of at least one well on each of the blocks over the three year license period.

China: The Corporation has signed a joint study agreement with Sinopec to evaluate unconventional oil and gas resource opportunities covering approximately 1.7 million acres in China.

Other Exploration Areas

Australia: The Corporation holds a 100% interest in an exploration license covering approximately 780,000 acres in the Carnarvon basin offshore Western Australia (WA-390-P Block, also known as Equus). The Corporation has drilled all of the 16 commitment wells on the block, 13 of which were natural gas discoveries. During 2011, the Corporation continued its appraisal program by drilling and flow testing certain wells. Appraisal of the discoveries is expected to be completed in mid-2012. Development plans were progressed during 2011, including the awarding of Front-End Engineering Design (FEED) contracts for a semi-submersible production platform, subsea gas gathering systems and an export pipeline in the fourth quarter. Negotiations with potential liquefaction partners will continue during 2012. In addition, during 2011, the Corporation signed a participation agreement under which it has the option to earn a 63% working interest in more than 6.2 million acres in the Beetaloo Basin, Northern Territory Australia.

Peru: The Corporation has an interest in Block 64 in Peru (Hess 50%). The operator has drilled several exploratory wells on the block that have encountered hydrocarbons. In the fourth quarter of 2011, the operator spudded the Situche Norte 4X well which is expected to be completed in mid-2012.

Brazil: The Corporation has a 40% interest in block BM-S-22 located offshore Brazil.

Sales Commitments

In the E&P segment, the Corporation has contracts to sell fixed quantities of its natural gas and natural gas liquids (NGL) production. The natural gas contracts principally relate to producing fields in Asia. The most significant of these commitments relates to the JDA where the minimum contract quantity of natural gas is estimated at 107 million mcf per year based on current entitlements under a sales contract expiring in 2027. There

are additional natural gas supply commitments on producing fields in Thailand and Indonesia which currently total approximately 45 million mcf per year under contracts expiring in years 2021 through 2029. The Corporation also has a commitment to supply approximately 15 million mcf of natural gas per year in the Bakken under a sales contract expiring in 2013. The Corporation also has NGL contracts relating to the Bakken, which commence in 2013. The minimum contract quantity under these contracts, which expire in 2023, is approximately 9.6 million barrels per year. The estimated total volume of production subject to sales commitments under all these contracts is approximately 2,422 million mcf of natural gas and 96 million barrels of NGL. The Corporation has not experienced any significant constraints in satisfying the committed quantities required by its sales commitments and it anticipates being able to meet future requirements from available proved and probable reserves.

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. These natural gas marketing activities are primarily conducted in the eastern portion of the United States, where the principal source of supply is purchased natural gas, not the Corporation’s production from the E&P segment. The Corporation has not experienced any significant constraints in obtaining the required supply of purchased natural gas.

Average selling prices and average production costs


	2011		2010		2009
Average selling prices (a)
Crude oil (per barrel)
United States	$	98.56	$	75.02	$	60.67
Europe (b)		80.18		58.11		47.02
Africa		88.46		65.02		48.91
Asia		111.71		79.23		63.01
Worldwide		89.99		66.20		51.62
Natural gas liquids (per barrel)
United States	$	58.59	$	47.92	$	36.57
Europe (b)		75.49		59.23		43.23
Asia		72.29		63.50		46.48
Worldwide		62.72		50.49		38.47
Natural gas (per mcf)
United States	$	3.39	$	3.70	$	3.36
Europe (b)		8.79		6.23		5.15
Asia and other		6.02		5.93		5.06
Worldwide		5.96		5.63		4.85
Average production (lifting) costs per barrel of oil equivalent produced (c)
United States	$	16.30	$	12.61	$	13.72
Europe (b)		25.13		17.55		15.77
Africa		15.95		11.00		10.93
Asia and other		10.62		8.16		7.65
Worldwide		17.40		12.61		12.12

(a)

Includes inter-company transfers valued at approximate market prices and the effect of the Corporation’s hedging activities.

(b)

The average selling prices in Norway for 2011 were $112.38 per barrel for crude oil, $62.07 per barrel for natural gas liquids and $9.77 per mcf for natural gas. The average production (lifting) cost in Norway in 2011 was $31.09 per barrel of oil equivalent produced. The average selling prices in Norway for 2010 were $79.47 per barrel for crude oil, $52.26 per barrel for natural gas liquids and $7.32 per mcf for natural gas. The average production (lifting) cost in Norway in 2010 was $18.33 per barrel of oil equivalent produced.

(c)

Production (lifting) costs consist of amounts incurred to operate and maintain the Corporation’s producing oil and gas wells, related equipment and facilities, transportation costs and production and severance taxes. The average production costs per barrel of oil equivalent reflect the crude oil equivalent of natural gas production converted on the basis of relative energy content (six mcf equals one barrel).

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, 2011


	Undeveloped Acreage (a)
	Gross		Net
	(In thousands)
United States		2,902		2,038
Europe (b)		2,651		1,266
Africa		8,009		4,625
Asia and other		11,250		6,960

Total (c)		24,812		14,889

(a)

Includes acreage held under production sharing contracts.

(b)

Gross and net undeveloped acreage in Norway was 841 thousand and 132 thousand, respectively.

(c)

Licenses covering approximately 29% of the Corporation’s net undeveloped acreage held at December 31, 2011 are scheduled to expire during the next three years pending the results of exploration activities. These scheduled expirations are largely in Asia, South America and the United States.

Gross and net developed acreage and productive wells at December 31, 2011


	Developed Acreage Applicable to Productive Wells				Productive Wells (a)
					Oil				Gas
	Gross		Net		Gross		Net		Gross		Net
	(In thousands)
United States		972		684		1,446		730		65		51
Europe (b)		1,015		787		282		189		21		2
Africa		9,832		933		903		130		—		—
Asia		2,200		630		80		10		461		102

Total		14,019		3,034		2,711		1,059		547		155

(a)

Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 28 gross wells and 19 net wells.

(b)

Gross and net developed acreage in Norway was 132 thousand and 43 thousand, respectively. Gross and net productive oil wells in Norway were 44 and 29, respectively. Gross and net productive gas wells in Norway were 9 and 1, respectively.

Number of net exploratory and development wells drilled at December 31


	Net Exploratory Wells						Net Development Wells
	2011		2010		2009		2011		2010		2009
Productive wells
United States		20		—		—		98		83		44
Europe		6		1		7		25		18		12
Africa		1		1		1		1		11		23
Asia and other		4		6		8		18		7		12

		31		8		16		142		119		91


Dry holes
United States		—		5		4		—		—		—
Europe		2		—		—		—		—		—
Africa		1		2		—		—		1		—
Asia and other		1		2		2		—		—		—

		4		9		6		—		1		—

Total		35		17		22		142		120		91

Number of wells in process of drilling at December 31, 2011


	Gross Wells		Net Wells
United States		203		71
Europe		10		8
Africa		1		1
Asia and other		21		6

Total		235		86

Marketing and Refining

Refining

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

HOVENSA: In January 2012, HOVENSA announced a decision to shut down its refinery in St. Croix, U.S. Virgin Islands and operate the complex as an oil storage terminal. For further discussion of the refinery shutdown, see Note 5, HOVENSA L.L.C. Joint Venture in the notes to the Consolidated Financial Statements.

Refining operations at HOVENSA consisted of crude units, a fluid catalytic cracking (FCC) unit and a delayed coker unit. The following table summarizes capacity and utilization rates for HOVENSA:


	Refinery Capacity	Refinery Utilization
	Refinery Capacity	2011			2010			2009
	(Thousands of barrels per day)
Crude	350*		81.1	%		78.0	%		80.3	%
Fluid catalytic cracker	150		71.7	%		66.5	%		70.2	%
Coker	58		77.4	%		78.3	%		81.6	%

*	HOVENSA’s crude oil refining capacity was reduced to 350,000 from 500,000 barrels per day in the first half of 2011.

Gross crude runs at HOVENSA averaged 284,000 barrels per day in 2011 compared with 390,000 barrels per day in 2010 and 402,000 barrels per day in 2009. These utilization rates reflect weaker refining margins, together with planned and unplanned maintenance.

Port Reading Facility: The Corporation owns and operates an FCC unit 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 2011 compared with 55,000 and 63,000 barrels per day, respectively in 2010 and 2009. Substantially all of Port Reading’s production is gasoline and heating oil. During 2010, the Port Reading refining facility was shut down for 41 days for a scheduled turnaround.

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 1,360 HESS^® gasoline stations at December 31, 2011, 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, 95% 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 for the years ended December 31:


	2011*		2010*		2009*
Refined petroleum product sales (thousands of barrels per day)
Gasoline		222		242		236
Distillates		123		120		134
Residuals		65		69		67
Other		20		40		36

Total refined petroleum product sales		430		471		473

Natural gas (thousands of mcf per day)		2,167		2,016		2,010
Electricity (megawatts round the clock)		4,374		4,140		4,306

*	Of total refined petroleum products sold, a total of approximately 37%, 41% and 45% was obtained from HOVENSA and Port Reading in 2011, 2010 and 2009, respectively. The Corporation purchased the balance from third parties under short-term supply contracts and spot purchases.

The Corporation does not anticipate any disruption to product supply for its Marketing operations as a result of the shutdown of HOVENSA’s refinery.

The Corporation owns 20 terminals with an aggregate storage capacity of 21 million barrels in its East Coast marketing areas. The Corporation also owns a terminal in St. Lucia with a storage capacity of 10 million barrels, which is operated for third party storage.

The Corporation has a 50% interest in Bayonne Energy Center, LLC, a joint venture established to build and operate a 512-megawatt natural gas fueled electric generating station in Bayonne, New Jersey. The joint venture plans to sell electricity into the New York City market by a direct connection with the Con Edison Gowanus substation. Construction of the facility began in mid-2010 and operations are due to commence in mid-2012.

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.

A subsidiary of the Corporation is exploring the development of fuel cell and hydrogen reforming technologies.

For additional financial information by segment see Note 19, Segment Information in the notes to the Consolidated 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

Gulf of Mexico Update

The Corporation has filed 183 Suspension of Operations (SOO) requests with the Bureau of Safety and Environmental Enforcement (BSEE). These SOO requests seek the BSEE’s approval for the extension of leases beyond their initial period where operations required to hold the leases have been delayed due to circumstances beyond the control of the Corporation. All 183 SOO requests have been approved for one year extensions. In addition, the Corporation has applied and received approval for exploration plans for two deepwater prospects. Further discussions have been held with the BSEE concerning the Corporation’s oil spill response plan for its Gulf of Mexico operations, which is also awaiting approval. This plan sets forth expectations for response training, drills and capabilities and the strategies, procedures and methods that the Corporation will employ in the event of a spill covering the following topics: spill response organization, incident command post, communications and notifications, spill detection and assessment (including worst case discharge scenarios), identification and protection of environmental resources, strategic response planning, mobilization and deployment of spill response equipment and personnel, oil and debris removal and disposal, the use of dispersants and chemical and biological agents, in-situ burning of oil, wildlife rehabilitation and documentation requirements.

Emergency Preparedness and Response Plans and Procedures

The Corporation has in place a series of business and asset-specific emergency preparedness, response and business continuity plans that detail procedures for rapid and effective emergency response and environmental mitigation activities. These plans are risk appropriate and are maintained, reviewed and updated as necessary to ensure their accuracy and suitability. Where appropriate, they are also reviewed and approved by the relevant host government authorities.

Responder training and drills are routinely held worldwide to assess and continually improve the effectiveness of the Corporation’s plans. The Corporation’s contractors, service providers, representatives from government agencies and, where applicable, joint venture partners participate in the drills to ensure that emergency procedures are comprehensive and can be effectively implemented.

To complement internal capabilities and to ensure coverage for its global operations, the Corporation maintains membership contracts with a network of local, regional and global oil spill response and emergency response organizations. At the regional and global level, these organizations include Clean Gulf Associates, Helix Well Containment Group (HWCG), Marine Well Containment Company (MWCC), Wild Well Control, National Response Corporation (NRC) and Oil Spill Response (OSR). Clean Gulf Associates is a regional spill response organization and HWCG and MWCC both provide the equipment and personnel to contain an underwater well control incident in the Gulf of Mexico. Wild Well Control provides firefighting, well control and engineering services globally. NRC and OSR are global response organizations and are available to assist the Corporation when needed anywhere in the world. In addition to owning response assets in their own right, these organizations maintain business relationships that provide immediate access to additional critical response support services if required. These owned response assets included nearly 300 recovery and storage vessels and barges, more than 250 skimmers, over 300,000 feet of boom, and significant quantities of dispersants and other ancillary equipment, including aircraft. If the Corporation were to engage these organizations to obtain additional critical response support services, it would fund such services and seek reimbursement under its insurance coverage described below. In certain circumstances, the Corporation pursues and enters into mutual aid agreements with other companies and government cooperatives to receive and provide oil spill response equipment and personnel support. The Corporation maintains close associations with emergency response organizations through its representation on the Executive Committee of Clean Gulf Associates and the Board of Directors of OSR.

The Corporation continues to participate in a number of industry-wide task forces that are studying better ways to assess the risk of and prevent onshore and offshore incidents, access and control blowouts in subsea environments, and improve containment and recovery methods. The task forces are working closely with the oil and gas industry and international government agencies to implement improvements and increase the effectiveness of oil spill prevention, preparedness, response and recovery processes.

Insurance Coverage and Indemnification

The Corporation maintains insurance coverage that includes coverage for physical damage to its property, third party liability, workers’ compensation and employers’ liability, general liability, sudden and accidental pollution, and other coverage. This insurance coverage is subject to deductibles, exclusions and limitations and there is no assurance that such coverage will adequately protect the Corporation against liability from all potential consequences and damages.

The amount of insurance covering physical damage to the Corporation’s property and liability related to negative environmental effects resulting from a sudden and accidental pollution event, excluding windstorm coverage in the Gulf of Mexico for which it is self insured, varies by asset, based on the asset’s estimated replacement value or the estimated maximum loss. In the case of a catastrophic event, first party coverage consists of two tiers of insurance. The first $250 million of coverage is provided through an industry mutual insurance group. Above this $250 million threshold, insurance is carried which ranges in value to over $2.0 billion in total, depending on the asset coverage level, as described above. Additionally, the Corporation carries insurance which provides third party coverage for general liability, and sudden and accidental pollution, up to $1 billion. Beginning in 2012, the first layer of insurance coverage has been increased to $300 million, and above that threshold, insurance is carried which ranges in value to over $2.25 billion.

Other insurance policies provide coverage for, among other things: charterer’s legal liability, in the amount of $500 million per occurrence and aircraft liability, in the amount of $300 million per occurrence.

The Corporation’s insurance policies renew at various dates each year. Future insurance coverage for the industry could increase in cost and may include higher deductibles or retentions, or additional exclusions or limitations. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are deemed economically acceptable.

Generally, the Corporation’s drilling contracts (and most of its other offshore services contracts) provide for a mutual hold harmless indemnity structure whereby each party to the contract (the Corporation and Contractor) indemnifies the other party for injuries or damages to their personnel and property regardless of fault. Variations include indemnity exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a party. Third-party claims, on the other hand, are generally allocated on a fault basis.

The Corporation is customarily responsible for, and indemnifies the Contractor against, all claims, including those from third-parties, to the extent attributable to pollution or contamination by substances originating from its reservoirs or other property (regardless of fault, including gross negligence and willful misconduct) and the Contractor is responsible for and indemnifies the Corporation for all claims attributable to pollution emanating from the Contractor’s property. Additionally, the Corporation is generally liable for all of its own losses and most third-party claims associated with catastrophic losses such as blowouts, cratering and loss of hole, regardless of cause, although exceptions for losses attributable to gross negligence and/or willful misconduct do exist. Lastly, many offshore services contracts include overall limitations of the Contractor’s liability equal to the value of the contract or a fixed amount, whichever is greater.

Under a standard joint operating agreement (JOA), each party is liable for all claims arising under the JOA, not covered by or in excess of insurance carried by the JOA, to the extent of its participating interest (operator or non-operator). Variations include indemnity exclusions where the claim is based upon the gross negligence and/or willful misconduct of a party in which case such party is solely liable. However, under some production sharing contracts between a governmental entity and commercial parties, liability of the commercial parties to the governmental entity is joint and several.

Environmental

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 spent $19 million in 2011 for environmental remediation. The Corporation anticipates capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, other than for the low sulfur requirements, of approximately $120 million in both 2012 and 2013. 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.

Number of Employees

The number of persons employed by the Corporation at year-end was approximately 14,350 in 2011 and 13,800 in 2010.

Other

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. The contents of the Corporation’s website are not incorporated by reference in this report. 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.

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

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 that additional risks relating to our securities may be described in a prospectus supplement if we issue securities in the future.

Our business and operating results are highly dependent on the market prices of crude oil, natural gas, refined petroleum products and electricity, which can be very volatile. 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, refined petroleum products and electricity, which are volatile and influenced by numerous factors beyond our control. Changes in commodity prices can also have a material impact on collateral and margin requirements under our derivative contracts. 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 as well as other supply and demand factors may also influence the selling prices of crude oil, natural gas, refined petroleum products and electricity. 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. In order to manage the potential volatility of cash flows and credit requirements, the Corporation utilizes significant bank credit facilities. An inability to renew or replace such credit facilities or access other sources of funding as they mature would negatively impact our liquidity.

If we fail to successfully increase our reserves, our future crude oil and natural gas production will be adversely impacted. 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 production and reserves, including proved undeveloped 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.

There are inherent uncertainties in estimating quantities of proved reserves and discounted future net cash flow, and actual quantities may be lower than estimated. 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 of our proved reserves and the related future net revenues. In addition, reserve estimates may be subject to downward or upward changes 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.

We are subject to changing laws and regulations and other governmental actions that can significantly and adversely affect our business. Federal, state, local, territorial and foreign laws and regulations relating to tax increases and retroactive tax claims, disallowance of tax credits and deductions, expropriation or nationalization of property, mandatory government participation, cancellation or amendment of contract rights, and changes in import and export regulations, limitations on access to exploration and development opportunities, as well as other political developments may affect our operations. The Dodd-Frank Wall Street Reform Act, enacted in 2010, delegated rulemaking responsibilities to carry out the Act to various U.S. government agencies. Our business could potentially be adversely impacted by one or more of the final

rules under this Act, when issued, including potential additional costs to engage in certain derivative transactions. We also 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. As a result of the accident in April 2010 at the BP p.l.c. (BP) operated Macondo prospect in the Gulf of Mexico (in which the Corporation was not a participant) and the ensuing significant oil spill, a temporary drilling moratorium was imposed in the Gulf of Mexico. While this moratorium has since been lifted, significant new regulations have been imposed and further legislation and regulations may be proposed, including an increase in the potential liability in the event of an oil spill. The new regulatory environment has resulted in a longer permitting process and higher costs.

Political instability in areas where we operate can adversely affect our business. 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. Political unrest in North Africa and the Middle East has affected and may continue to affect our operations in these areas as well as oil and gas markets generally. The threat of terrorism around the world also poses additional risks to the operations of the oil and gas industry.

Our oil and gas operations are subject to environmental risks and environmental laws and regulations that can result in significant costs and liabilities. Our oil and gas operations, like those of the industry, are subject to environmental risks 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. For example, the accident at the BP operated Macondo prospect in April 2010 resulted in a significant release of crude oil which caused extensive environmental and economic 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.

Concerns have been raised in certain jurisdictions where we have operations concerning the safety and environmental impact of the drilling and development of unconventional oil and gas resources, particularly using the process of hydraulic fracturing. While we believe that these operations can be conducted safely and with minimal impact on the environment, regulatory bodies are responding to these concerns and may impose moratoriums and new regulations on such drilling operations that would likely have the effect of prohibiting or delaying such operations and increasing their cost. For example, a moratorium prohibiting hydraulic fracturing is currently impacting the Corporation’s operations in France.

Concerns about climate change may result in significant operational changes and expenditures and reduced demand for our products. 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, which may result in 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.

Our industry is highly competitive and many of our competitors are larger and have greater resources than we have. 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 petroleum 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, resulting in increased capital and operating costs.

Catastrophic events, whether naturally occurring or man-made, may materially affect our operations and financial conditions. Our oil and gas operations are subject to unforeseen occurrences which have affected us from time to time and which may damage or destroy assets, interrupt operations and have other significant adverse effects. Examples of catastrophic risks include hurricanes, fires, explosions and blowouts, such as the accident at the Macondo prospect operated by BP in the Gulf of Mexico in 2010. Although we maintain insurance coverage against property and casualty losses, there can be no assurance that such insurance will adequately protect the Corporation against liability from all potential consequences and damages. Moreover, some forms of insurance may be unavailable in the future or be available only on terms that are deemed economically unacceptable.

Item 3. Legal Proceedings

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 was 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 2010 and 2011, additional cases were settled including an action brought in state court by the State of New Hampshire. Two separate cases brought by the State of New Jersey and the Commonwealth of Puerto Rico remain unresolved. In 2007, a pre-tax charge of $40 million was recorded to cover all of the known MTBE cases against 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 the 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 Environmental Protection Agency (EPA) to study the same contamination. The 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 for all parties. 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 a 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.

On July 25, 2011, the Virgin Islands Department of Planning and Natural Resources commenced an enforcement action against HOVENSA by issuance of documents titled “Notice Of Violation, Order For Corrective Action, Notice Of Assessment of Civil Penalty, Notice Of Opportunity For Hearing” (the “NOVs”). The NOVs assert violations of Virgin Islands Air Pollution Control laws and regulations arising out of odor incidents on St. Croix in May 2011 and proposes total penalties of $210,000. HOVENSA is engaging in settlement discussions with the Government of the Virgin Islands, but believes that it has good defenses against the asserted violations.

On December 16, 2010, the Virgin Islands Department of Planning and Natural Resources commenced four separate enforcement actions against HOVENSA by issuance of documents titled “Notice Of Violation, Order For Corrective Action, Notice Of Assessment of Civil Penalty, Notice Of Opportunity For Hearing”. The NOVs assert violations of Virgin Islands Air Pollution Control laws and regulations arising out of air release incidents

at the HOVENSA refinery in 2009 and 2010 and propose total penalties of $1,355,000. HOVENSA anticipates settling this matter in the first quarter of 2012.

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 refinery, 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 are continuing to vigorously defend this matter and do not believe that this matter will result in a material liability as they believe that they have strong defenses against this complaint.

The Corporation periodically receives notices from the 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, the 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, the 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. The Corporation cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such proceedings is not expected to have a material adverse effect on the financial condition, results of operations or cash flows of the Corporation.

PART II

Item 5.

Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities

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:

2011

2010

Quarter Ended

High

Low

High

Low

March 31

87.40

76.00

66.49

55.89

June 30

87.19

67.65

66.22

48.70

September 30

77.12

50.42

59.79

48.71

December31

66.49

46.66

76.98

59.23

Performance Graph

Set forth below is a line graph comparing the five year shareholder return on a $100 investment in the Corporation’s common stock assuming reinvestment of dividends, against the cumulative total returns for the following indexes:

•

Standard & Poor’s 500 Stock Index, which includes the Corporation, and

•

AMEX Oil Index, which is comprised of companies involved in various phases of the oil industry including the Corporation.

Comparison of Five-Year Shareholder Returns

Years Ended December 31,

LOGO

Holders

At December 31, 2011, there were 5,635 stockholders (based on the number of holders of record) who owned a total of 339,975,610 shares of common stock.

Dividends

Cash dividends on common stock totaled $0.40 per share ($0.10 per quarter) during 2011, 2010 and 2009.

Equity Compensation Plans

Following is information on the Registrant’s equity compensation plans at December 31, 2011:


Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c)
Equity compensation plans approved by security holders		13,570,000	$	61.68		8,403,000	*
Equity compensation plans not approved by security holders**		—		—		—

*	These securities may be awarded as stock options, restricted stock or other awards permitted under the Registrant’s equity compensation plan.

**	The Corporation has a Stock Award Program pursuant to which each non-employee director received approximately $150,000 in value of the Corporation’s common stock in 2011. These awards were made from shares purchased by the Corporation in the open market.

See Note 11, Share-based Compensation in the notes to the Consolidated Financial Statements for further discussion of the Corporation’s equity compensation plans.

Item 6.

Selected Financial Data

A five-year summary of selected financial data follows:


	2011			2010			2009			2008			2007
	(Millions of dollars, except per share amounts)
Sales and other operating revenues
Crude oil and natural gas liquids	$	9,065		$	7,235		$	5,665		$	7,764		$	6,303
Natural gas (including sales of purchased gas)		5,526			5,723			5,894			8,800			6,877
Refined petroleum products		19,459			16,103			12,931			19,765			14,741
Electricity		2,957			3,165			3,408			3,451			2,322
Convenience store sales and other operating revenues		1,459			1,636			1,716			1,354			1,484

Total	$	38,466		$	33,862		$	29,614		$	41,134		$	31,727

Net income attributable to Hess Corporation	$	1,703	(a)	$	2,125	(b)	$	740	(c)	$	2,360	(d)	$	1,832	(e)

Earnings per share
Basic	$	5.05		$	6.52		$	2.28		$	7.35		$	5.86
Diluted	$	5.01		$	6.47		$	2.27		$	7.24		$	5.74
Total assets	$	39,136		$	35,396		$	29,465		$	28,589		$	26,131
Total debt	$	6,057		$	5,583		$	4,467		$	3,955		$	3,980
Total equity	$	18,592		$	16,809		$	13,528		$	12,391		$	10,000
Dividends per share of common stock	$	.40		$	.40		$	.40		$	.40		$	.40

(a)

Includes after-tax charges totaling $694 million relating to the shutdown of the HOVENSA L.L.C. (HOVENSA) refinery, asset impairments and an increase in the United Kingdom supplementary tax rate, partially offset by after-tax income of $413 million relating to gains on asset sales.

(b)

Includes after-tax income of $1,130 million relating to gains on asset sales, partially offset by charges totaling $694 million for an asset impairment, an impairment of the Corporation’s equity investment in HOVENSA, dry hole expense and premiums on repurchases of fixed-rate public notes.

(c)

Includes after-tax expenses totaling $104 million relating to repurchases of fixed-rate public notes, retirement benefits, employee severance costs and asset impairments, partially offset by after-tax income totaling $101 million principally relating to the resolution of a United States royalty dispute.

(d)

Includes after-tax expenses totaling $26 million primarily relating to asset impairments and hurricanes in the Gulf of Mexico.

(e)

Includes net after-tax expenses of $75 million primarily relating to asset impairments, estimated production imbalance settlements and a charge for MTBE litigation, partially offset by income from LIFO inventory liquidations and gains on asset sales.

Item 7.

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

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 2011 was $1,703 million compared with $2,125 million in 2010 and $740 million in 2009. Diluted earnings per share were $5.01 in 2011 compared with $6.47 in 2010 and $2.27 in 2009. A table of items affecting comparability between periods is shown on page 23.

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 1,573 million barrels of oil equivalent (boe) at December 31, 2011 compared with 1,537 million boe at December 31, 2010 and 1,437 million boe at December 31, 2009.

E&P earnings were $2,675 million in 2011, $2,736 million in 2010 and $1,042 million in 2009. Average realized crude oil selling prices were $89.99 per barrel in 2011, $66.20 in 2010 and $51.62 in 2009, including the impact of hedging. Average realized natural gas selling prices were $5.96 per mcf in 2011, $5.63 in 2010 and $4.85 in 2009. Production averaged 370,000 barrels of oil equivalent per day (boepd) in 2011, a decrease of 48,000 boepd or 11% from 2010. Production averaged 408,000 boepd in 2009. The Corporation estimates that total worldwide production will average between 370,000 and 390,000 boepd in 2012, excluding the impact of asset sales and any Libyan production.

The following is an update of significant E&P activities during 2011:

•

In North Dakota, net production from the Bakken oil shale play averaged approximately 30,000 boepd during 2011 and 38,000 boepd for the fourth quarter 2011. The Corporation forecasts Bakken production will average 60,000 boepd for the full year of 2012 and is targeted to reach 120,000 boepd in 2015.

•

The Corporation and its partner sanctioned the development of the Tubular Bells Field (Hess 57%) in the Mississippi Canyon Block 725 Area in the deepwater Gulf of Mexico. In 2012, field development will be advanced with the construction of a floating production system and development drilling is scheduled to start in the second quarter. First production is anticipated in 2014.

•

In the third quarter of the year, the Corporation announced the acquisition of approximately 185,000 net acres in the Utica Shale play in eastern Ohio. The Corporation entered into agreements to acquire approximately 85,000 net acres for approximately $750 million, principally through the acquisition of Marquette Exploration, LLC. In October 2011, the Corporation completed the acquisition of a 50% undivided interest in CONSOL Energy Inc.’s (CONSOL) nearly 200,000 acres in the Utica Shale play for $59 million in cash at closing and the agreement to fund 50% of CONSOL’s share of the drilling costs up to $534 million within a 5-year period. Appraisal of the Utica acreage commenced in the fourth quarter and will continue during 2012 with the acquisition of seismic and the planned drilling of 29 wells.

•

The Corporation filed a Notice of Discovery with the Ministry for Energy of Ghana for the Paradise-1 exploration well in the Deepwater Tano Cape Three Points block. The well encountered an estimated 490 net feet of oil and gas condensate pay over three separate intervals. The Corporation is operator and has a 90% working interest in the license. The Corporation anticipates commencing additional exploration drilling in the first quarter of 2012, subject to government approvals and rig availability.

•

In 2011, the Corporation drilled the Andalan-1 well on the Semai V block, offshore Indonesia (Hess 100%). The well encountered reservoir sands and hydrocarbons but not in commercial quantities. This well, along with a follow up well, was expensed in the fourth quarter. In September 2011, the operator of Block CA-1 in Brunei (Hess 14%) spud the Julong Center well. This well also failed to find commercial quantities of hydrocarbons and was expensed.

•

In February 2011, the Corporation completed the sale of its interests in certain natural gas producing assets located in the United Kingdom North Sea for cash proceeds of $359 million, after post-closing adjustments, resulting in a pre-tax gain of $343 million ($310 million after income taxes). In August 2011, the Corporation completed the sale of its interests in the Snorre Field (Hess 1%), offshore Norway and the Cook Field (Hess 28%) in the United Kingdom North Sea for cash proceeds of $131 million, after post-closing adjustments. These disposals resulted in non-taxable gains totaling $103 million.

Status of Libyan Operations

Marketing and Refining

The Corporation’s strategy for the M&R segment is to deliver strong operating performance and generate free cash flow. In January 2012, HOVENSA announced a decision to shut down its refinery in St. Croix, U.S. Virgin Islands and operate the complex as an oil storage terminal. Results from M&R activities amounted to losses of $584 million in 2011, losses of $231 million in 2010 and earnings of $127 million in 2009. Refining operations generated losses of $728 million in 2011, $445 million in 2010 and $87 million in 2009. Refining results include after-tax charges of $525 million in 2011 and $289 million in 2010 related to the Corporation’s investment in HOVENSA. Marketing earnings were $185 million in 2011, $215 million in 2010 and $168 million in 2009.

Liquidity and Capital and Exploratory Expenditures

Net cash provided by operating activities was $4,984 million in 2011, $4,530 million in 2010 and $3,046 million in 2009. At December 31, 2011, cash and cash equivalents totaled $351 million compared with $1,608 million at December 31, 2010, principally due to increased capital expenditures. Total debt was $6,057 million at December 31, 2011 and $5,583 million at December 31, 2010. The Corporation’s debt to capitalization ratio at December 31, 2011 was 24.6% compared with 24.9% at the end of 2010.

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


	2011		2010		2009
	(Millions of dollars)
Exploration and Production
United States	$	4,305	$	2,935	$	1,200
International		3,039		2,822		1,927

Total Exploration and Production		7,344		5,757		3,127
Marketing, Refining and Corporate		118		98		118

Total capital and exploratory expenditures	$	7,462	$	5,855	$	3,245

Exploration expenses charged to income included above:
United States	$	197	$	154	$	144
International		259		209		183

Total exploration expenses charged to income included above	$	456	$	363	$	327

The Corporation anticipates investing $6.8 billion in capital and exploratory expenditures in 2012, substantially all of which is targeted for E&P operations.

Consolidated Results of Operations

The after-tax income (loss) by major operating activity is summarized below for the years ended December 31:


	2011			2010			2009
	(Millions of dollars, except per share data)
Exploration and Production	$	2,675		$	2,736		$	1,042
Marketing and Refining		(584	)		(231	)		127
Corporate		(154	)		(159	)		(205	)
Interest expense		(234	)		(221	)		(224	)

Net income attributable to Hess Corporation	$	1,703		$	2,125		$	740

Net income per share — diluted	$	5.01		$	6.47		$	2.27

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 27 through 30.


	2011			2010			2009
	(Millions of dollars)
Exploration and Production	$	244		$	732		$	45
Marketing and Refining		(525	)		(289	)		12
Corporate		—			(7	)		(60	)

	$	(281	)	$	436		$	(3	)

In the following discussion and elsewhere in this report, 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

Exploration and Production

Following is a summarized income statement of the Corporation’s E&P operations for the years ended December 31:


	2011		2010		2009
	(Millions of dollars)
Sales and other operating revenues*	$	10,047	$	8,744	$	6,835
Other, net		464		1,233		207

Total revenues and non operating income		10,511		9,977		7,042

Costs and expenses
Production expenses, including related taxes		2,352		1,924		1,805
Exploration expenses, including dry holes and lease impairment		1,195		865		829
General, administrative and other expenses		313		281		255
Depreciation, depletion and amortization		2,305		2,222		2,113
Asset impairments		358		532		54

Total costs and expenses		6,523		5,824		5,056

Results of operations before income taxes		3,988		4,153		1,986
Provision for income taxes		1,313		1,417		944

Results of operations attributable to Hess Corporation	$	2,675	$	2,736	$	1,042

*	Amounts differ from E&P operating revenues in Note 19, Segment Information in the notes to the Consolidated Financial Statements primarily due to the exclusion of sales of hydrocarbons purchased from third parties.

After considering the E&P items affecting comparability of earnings between periods in the table on page 27, the remaining changes in E&P earnings are primarily attributable to changes in selling prices, production and sales volumes, operating costs, exploration expenses, income taxes and foreign exchange, as discussed below.

Selling Prices: Higher average selling prices increased E&P revenues by approximately $2,400 million in 2011 compared with 2010. Higher average selling prices increased E&P revenues by approximately $1,775 million in 2010 compared with 2009.

The Corporation’s average selling prices were as follows for the years ended December 31:


	2011		2010		2009
Crude oil — per barrel (including hedging)
United States	$	98.56	$	75.02	$	60.67
Europe		80.18		58.11		47.02
Africa		88.46		65.02		48.91
Asia		111.71		79.23		63.01
Worldwide		89.99		66.20		51.62
Crude oil — per barrel (excluding hedging)
United States	$	98.56	$	75.02	$	60.67
Europe		80.18		58.11		47.02
Africa		110.28		78.31		60.79
Asia		111.71		79.23		63.01
Worldwide		95.60		71.40		56.74
Natural gas liquids — per barrel
United States	$	58.59	$	47.92	$	36.57
Europe		75.49		59.23		43.23
Asia		72.29		63.50		46.48
Worldwide		62.72		50.49		38.47


	2011		2010		2009
Natural gas — per mcf
United States	$	3.39	$	3.70	$	3.36
Europe		8.79		6.23		5.15
Asia and other		6.02		5.93		5.06
Worldwide		5.96		5.63		4.85

In October 2008, the Corporation closed Brent crude oil hedges covering 24,000 barrels per day from 2009 through 2012 by entering into offsetting contracts with the same counterparty. The deferred after-tax losses as of the date the hedge positions were closed are recorded in earnings as the contracts mature. Crude oil hedges reduced E&P earnings by $327 million ($517 million before income taxes) in 2011, $338 million ($533 million before income taxes) in 2010 and $337 million ($533 million before income taxes) in 2009. The remaining realized after-tax losses from the closed hedge positions will be approximately $325 million in 2012. The Corporation also entered into Brent crude oil hedges using fixed-price swap contracts to hedge 120,000 boepd of crude oil sales volumes for the full year of 2012 at an average price of $107.70 per barrel.

Production and Sales Volumes: The Corporation’s crude oil and natural gas production was 370,000 boepd in 2011 compared with 418,000 boepd in 2010 and 408,000 boepd in 2009. The principal reasons for the reduction are described below. Approximately 72% in 2011, 73% in 2010 and 72% in 2009 of the Corporation’s production was from crude oil and natural gas liquids. The Corporation currently estimates that its 2012 production will average between 370,000 and 390,000 boepd, excluding the impact of asset sales and any Libyan production.

The Corporation’s net daily worldwide production was as follows for the years ended December 31:


	2011		2010		2009
	(In thousands)
Crude oil — barrels per day
United States		81		75		60
Europe		89		88		83
Africa		66		113		120
Asia		13		13		16

Total		249		289		279

Natural gas liquids — barrels per day
United States		13		14		11
Europe		3		3		3
Asia		1		1		—

Total		17		18		14

Natural gas — mcf per day
United States		100		108		93
Europe		81		134		151
Asia and other		442		427		446

Total		623		669		690

Barrels of oil equivalent — per day*		370		418		408

United States: Crude oil production in the United States was higher in 2011 compared with 2010, primarily due to new wells in the Bakken oil shale play, partly offset by lower production due to a shut-in well at the Llano Field. Natural gas production was lower in 2011 compared with 2010, primarily due to this shut-in well at the Llano Field. Crude oil and natural gas production was higher in 2010 compared with 2009, primarily due to new production from the Shenzi, Llano, Conger and Bakken fields.

Europe: Crude oil production was comparable in 2011 and 2010, as higher production from Russia was largely offset by lower production from the Corporation’s United Kingdom North Sea assets. Crude oil production was higher in 2010 compared with 2009, due to higher production in Russia and in Norway following the acquisition of additional interests in the Valhall and Hod fields in 2010. Natural gas production was lower in 2011 compared with 2010, primarily due to the sale in February 2011 of certain natural gas producing assets in the United Kingdom North Sea. Natural gas production was lower in 2010 compared with 2009, primarily due to downtime at certain United Kingdom gas fields.

Africa: Crude oil production decreased in 2011 compared with 2010 due to the suspension of production in Libya following civil unrest, the exchange in September 2010 of the Corporation’s interests in Gabon for increased interests in Norway, lower production entitlement in Equatorial Guinea and Algeria as a result of higher selling prices, and natural decline in Equatorial Guinea. Crude oil production decreased in 2010 compared with 2009 following the exchange of Gabon for additional interests in the Valhall and Hod fields in Norway and lower entitlement to Algerian production.

Asia and other: Natural gas production in 2011 was higher than 2010, primarily due to higher total nominations at the Joint Development Area of Malaysia and Thailand (JDA) and the adjacent Block PM301 in Malaysia and first production from the Gajah Baru Complex at the Natuna A Field in Indonesia, which commenced production in the fourth quarter of 2011. Natural gas production in 2010 was lower than in 2009, primarily due to downtime at the Pangkah Field in Indonesia and a temporary shut-in at the Bumi Field in the JDA.

Sales Volumes: Lower sales volumes and other operating revenues decreased revenue by approximately $1,100 million in 2011 compared with 2010 and higher sales volumes and other operating revenues increased revenue by $135 million in 2010 compared with 2009.

Operating Costs and Depreciation, Depletion and Amortization: Cash operating costs, consisting of production expenses and general and administrative expenses, increased by $460 million in 2011 compared with 2010 and increased by $145 million in 2010 compared with 2009. The increase in 2011 was primarily due to higher production taxes as a result of higher selling prices, together with higher operating and maintenance expenses, mainly in Norway and in the Bakken oil shale play. The increase in costs in 2010 compared to 2009 was primarily due to higher production taxes as a result of higher selling prices.

Depreciation, depletion and amortization charges increased by $83 million in 2011 and $109 million in 2010, compared with the corresponding amounts in prior years. The increases in both 2011 and 2010 were primarily due to higher per barrel costs, reflecting higher finding and development costs. In addition, the higher total per barrel costs in 2011 resulted from a greater proportion of production volumes from the Bakken.

Excluding items affecting comparability between periods, cash operating costs per barrel of oil equivalent were $19.71 in 2011, $14.45 in 2010 and $13.70 in 2009. Depreciation, depletion and amortization costs per barrel of oil equivalent were $17.06 in 2011, $14.56 in 2010 and $14.19 in 2009. For 2012, cash operating costs are estimated to be in the range of $20.00 to $21.00 per barrel and depreciation, depletion and amortization costs are estimated to be in the range of $20.50 to $21.50 per barrel, resulting in total unit costs in the range of $40.50 to $42.50 per barrel of oil equivalent, excluding Libyan operations.

Exploration Expenses: Exploration expenses increased in 2011 compared to 2010, mainly due to higher dry hole expenses. Dry hole expenses included amounts relating to two exploration wells on the Semai V Block, offshore Indonesia and a well in the North Red Sea Block 1, offshore Egypt. Exploration expenses also increased in 2010 from 2009, primarily due to higher lease amortization.

Income Taxes: Excluding the impact of items affecting comparability, the effective income tax rates for E&P operations were 38% in 2011, 44% in 2010 and 48% in 2009. The decrease in the effective income tax rate in 2011 compared with 2010 was predominantly due to the suspension of Libyan operations. The effective income tax rate for E&P operations in 2012 is estimated to be in the range of 36% to 40%, excluding Libyan operations.

Foreign Exchange: The after-tax foreign currency losses were $16 million in 2011, $9 million in 2010 and $10 million in 2009.

Items Affecting Comparability of Earnings: Reported E&P earnings include the following items affecting comparability of income (expense) before and after income taxes for the years ended December 31:


	Before Income Taxes									After Income Taxes
	2011			2010			2009			2011			2010			2009
	(Millions of dollars)
Gains on asset sales	$	446		$	1,208		$	—		$	413		$	1,130		$	—
Royalty dispute resolution		—			—			143			—			—			89
Asset impairments		(358	)		(532	)		(54	)		(140	)		(334	)		(26	)
Dry hole expense		—			(101	)		—			—			(64	)		—
Reductions in carrying values of assets		—			—			(23	)		—			—			(18	)
Income tax adjustment		—			—			—			(29	)		—			—

	$	88		$	575		$	66		$	244		$	732		$	45

2011: In February 2011, the Corporation completed the sale of its interests in the Easington Catchment Area (Hess 30%), the Bacton Area (Hess 23%), the Everest Field (Hess 19%) and the Lomond Field (Hess 17%) in the United Kingdom North Sea for cash proceeds of $359 million, after post-closing adjustments. These disposals resulted in pre-tax gains totaling $343 million ($310 million after income taxes). These assets had a productive capacity of approximately 15,000 boepd. The total combined net book value of the disposed assets prior to the sale was $16 million, including allocated goodwill of $14 million. In August 2011, the Corporation completed the sale of its interests in the Snorre Field (Hess 1%), offshore Norway and the Cook Field (Hess 28%) in the United Kingdom North Sea for cash proceeds of $131 million, after post-closing adjustments. These disposals resulted in non-taxable gains totaling $103 million. The total combined net book value of the disposed assets prior to the sale was $28 million, including allocated goodwill of $11 million.

In the third quarter of 2011, the Corporation recorded impairment charges of $358 million ($140 million after income taxes) related to increases in the Corporation’s estimated abandonment liabilities primarily for non-producing properties which resulted in the book value of the properties exceeding their fair value. See Note 9, Asset Retirement Obligations in the notes to the Consolidated Financial Statements.

In July 2011, the United Kingdom increased the supplementary tax rate on petroleum operations to 32% from 20% with an effective date of March 24, 2011. As a result, the Corporation recorded a charge of $29 million to increase the deferred tax liability in the United Kingdom.

2010: The Corporation completed the exchange of its interests in Gabon and the Clair Field in the United Kingdom for additional interests of 28% and 25%, respectively, in the Valhall and Hod fields in Norway. This non-monetary transaction, which was recorded at fair value, resulted in a pre-tax gain of $1,150 million ($1,072 million after income taxes). The Corporation also completed the sale of its interest in the Jambi Merang natural gas development project in Indonesia for a gain of $58 million.

The Corporation recorded a charge of $532 million ($334 million after income taxes) to fully impair the carrying value of its 55% interest in the West Mediterranean Block 1 concession (West Med Block), located offshore Egypt. This interest was acquired in 2006 and included four natural gas discoveries and additional exploration prospects. The Corporation and its partners subsequently explored and further evaluated the area, made a fifth discovery, conducted development planning, and held negotiations with the Egyptian authorities to amend the existing gas sales agreement. In September 2010, the Corporation and its partners notified the Egyptian authorities of their decision to cease exploration activities and to relinquish a significant portion of the block. As a result, the Corporation fully impaired the carrying value of its interest in the West Med Block. The West Med Block was relinquished in 2011. The Corporation also recorded $101 million ($64 million after income taxes) of dry hole expenses related to previously suspended well costs on the West Med Block offshore Egypt and Block BM-S-22 offshore Brazil, both of which were drilled prior to 2010.

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 (predecessor to the Bureau of Ocean Energy Management, Regulation and Enforcement) relating to royalty relief under the Deep Water Royalty Relief Act of 1995. As a result, the Corporation recognized after-tax income of $89 million to reverse all previously recorded royalties covering the periods from 2003 to 2009. The pre-tax amount of $143 million was reported in Other, net in the Statement of Consolidated Income.

The Corporation recorded total asset impairment charges of $54 million ($26 million after income taxes) to reduce the carrying value of two-short lived fields in the United Kingdom North Sea. Pre-tax charges of approximately $23 million ($18 million after income taxes) were recorded to impair the carrying values of production equipment and to write down materials inventories in Equatorial Guinea and the United States. The pre-tax amount of most of the inventory write downs was reported in Production expenses in the Statement of Consolidated Income.

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, exploration expenses, industry cost inflation, changes in foreign exchange rates and income tax rates, the effects of weather, political risk, environmental risk and catastrophic risk. In addition, as a result of the oil spill in 2010 at the BP p.l.c. operated Macondo prospect in the Gulf of Mexico, there have been and there may be further changes in laws and regulations that could impact the Corporation’s future drilling operations and increase its potential liability in the event of an oil spill. For a more comprehensive description of the risks that may affect the Corporation’s E&P business, see Item 1A. Risk Factors Related to Our Business and Operations.

Marketing and Refining

Results from M&R activities were losses of $584 million in 2011, losses of $231 million in 2010 and earnings of $127 million in 2009. Excluding the items affecting comparability reflected in the table on page 23 and discussed below, results were losses of $59 million in 2011 and earnings of $58 million in 2010 and $115 million in 2009.

Refining: Refining results consist of the Corporation’s share of HOVENSA’s losses, together with the results of Port Reading and other miscellaneous operating activities. Refining losses were $728 million in 2011 (including $525 million of after-tax losses related to the impairment recorded by HOVENSA and other charges due to the decision to shut down the refinery in St. Croix), $445 million in 2010 (including a $289 million after-tax charge to reduce the carrying value of the Corporation’s equity investment in HOVENSA) and $87 million in 2009 (including a benefit of $12 million due to an income tax adjustment).

In 2011, HOVENSA experienced continued substantial operating losses due to global economic conditions and competitive disadvantages versus other refiners, despite efforts to improve operating performance by reducing refining capacity to 350,000 from 500,000 barrels per day in the first half of the year. Operating losses were also projected to continue. In January 2012, HOVENSA announced a decision to shut down its refinery and operate the complex as an oil storage terminal. As a result of these developments, HOVENSA prepared an impairment analysis as of December 31, 2011, which concluded that undiscounted future cash flows would not recover the carrying value of its long-lived assets, and recorded an impairment charge and other charges related to the decision to shut down the refinery. For 2011, the Corporation recorded a total of $1,073 million of losses from its equity investment in HOVENSA. These pre-tax losses included $875 million ($525 million after income taxes) due to the impairment recorded by HOVENSA and other charges associated with its decision to shut down the refinery. The Corporation’s share of the impairment related losses recorded by HOVENSA represents an amount equivalent to the Corporation’s financial support to HOVENSA at December 31, 2011, its planned future funding commitments for costs related to the refinery shutdown, and a charge of $135 million for the write-off of related assets held by the subsidiary which owns the Corporation’s investment in HOVENSA. At December 31, 2011, the Corporation has a liability of $487 million for its planned funding commitments, which is expected to be incurred in 2012. A deferred income tax benefit of $350 million, consisting primarily of U.S. income taxes, has been recorded on the Corporation’s share of HOVENSA’s impairment and refinery shutdown related charges.

In December 2010, the Corporation recorded an impairment charge of $300 million before income taxes ($289 million after income taxes) to reduce the carrying value of its equity investment in HOVENSA, which was recorded in Income (loss) from equity investment in HOVENSA L.L.C., on the Statement of Consolidated Income. The investment had been adversely affected by consecutive annual operating losses resulting from continued weak refining margins and refinery utilization, and a fourth quarter 2010 debt rating downgrade. As a result of a strategic assessment in 2010, HOVENSA decided to lower its crude oil refining capacity to 350,000 from 500,000 barrels per day in 2011. The Corporation performed an impairment analysis and concluded that its investment had experienced an other than temporary decline in value. For discussion of the impairment charge, see Note 5, HOVENSA L.L.C. Joint Venture in the notes to the Consolidated Financial Statements.

Excluding items affecting comparability discussed above, the Corporation’s share of HOVENSA’s results was a loss of $198 million in 2011, $137 million in 2010 ($222 million before income taxes) and $141 million ($230 million before income taxes) in 2009. U.S. Virgin Island income taxes have not been recorded on the Corporation’s share of HOVENSA’s 2011 results due to cumulative operating losses. These results reflect lower refining margins, higher fuel costs and lower sales volumes. During 2010, the fluid catalytic cracking unit at HOVENSA was shut down for a scheduled turnaround. The Corporation’s share of HOVENSA’s turnaround expenses was approximately $20 million after income taxes.

Other after-tax refining results, principally from Port Reading operations, were a loss of $5 million in 2011, a loss of $19 million in 2010 and income of $42 million in 2009. During 2010, the Port Reading refining facility was shut down for 41 days for a scheduled turnaround. The after-tax expenses for the Port Reading turnaround were approximately $30 million. The turnaround expenses are included in Other operating expenses in the Statement of Consolidated Income.

The following table summarizes refinery utilization rates for the years ended December 31:


	Refinery Capacity	Refinery Utilization
	(Thousands of barrels per day)	2011			2010			2009
HOVENSA
Crude	350*		81.1	%		78.0	%		80.3	%
Fluid catalytic cracker	150		71.7	%		66.5	%		70.2	%
Coker	58		77.4	%		78.3	%		81.6	%
Port Reading	70		90.0	%		78.1	%		90.2	%

*	HOVENSA’s crude oil refining capacity was reduced to 350,000 from 500,000 barrels per day in the first half of 2011.

Marketing: Marketing operations, which consist principally of retail gasoline and energy marketing activities, generated income of $185 million in 2011, $215 million in 2010 and $168 million in 2009. The decrease in earnings in 2011 compared with 2010 was due to lower sales volumes and lower margins. The increase in earnings in 2010 compared with 2009 reflected improved margins from the weak economic environment in 2009.

The table below summarizes marketing sales volumes for the years ended December 31:


	2011		2010		2009
Refined petroleum product sales (thousands of barrels per day)		430		471		473
Natural gas (thousands of mcf per day)		2,167		2,016		2,010
Electricity (megawatts round the clock)		4,374		4,140		4,306

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 a loss of $41 million in 2011, a loss of $1 million in 2010 and earnings of $46 million in 2009.

Marketing expenses increased in 2011 compared with 2010 reflecting higher retail credit card fees, maintenance, environmental and employee related expenses. Marketing expenses increased in 2010 compared with 2009, principally reflecting changes in retail credit card fees.

The Corporation’s future M&R earnings may be impacted by supply and demand factors, volatility in margins, credit risks, the effects of weather, competitive industry conditions, political risk, environmental risk and catastrophic risk. For a more comprehensive description of the risks that may affect the Corporation’s M&R business, see Item 1A. Risk Factors Related to Our Business and Operations.

Corporate

The following table summarizes corporate expenses for the years ended December 31:


	2011			2010			2009
	(Millions of dollars)
Corporate expenses (excluding items affecting comparability)	$	260		$	256		$	227
Income taxes (benefits)		(106	)		(104	)		(82	)

Net corporate expenses		154			152			145
Items affecting comparability between periods, after-tax		—			7			60

Total corporate expenses, after-tax	$	154		$	159		$	205

Excluding items affecting comparability between periods, net corporate expenses were comparable in 2011 and 2010. The increase in net corporate expenses in 2010 compared with 2009 primarily reflects higher employee and insurance costs and bank facility fees. After-tax corporate expenses in 2012 are estimated to be in the range of $160 million to $170 million.

In 2010, the Corporation recorded a pre-tax charge of $11 million ($7 million after income taxes) related to the repurchase of the remaining $116 million of fixed-rate public notes that were scheduled to mature in 2011. In 2009, the Corporation recorded pre-tax charges of $54 million ($34 million after income taxes) related to the repurchase of $546 million in fixed-rate public notes that were scheduled to mature in 2011 and $42 million ($26 million after income taxes) relating to retirement benefits and employee severance costs. The pre-tax charges in connection with the debt repurchases were recorded in Other, net, and the pre-tax amounts of the retirement benefits and severance costs were recorded in General and administrative expenses in the Statement of Consolidated Income.

Interest

Interest expense was as follows for the years ended December 31:


	2011			2010			2009
	(Millions of dollars)
Total interest incurred	$	396		$	366		$	366
Capitalized interest		(13	)		(5	)		(6	)

Interest expense before income taxes		383			361			360
Income taxes (benefits)		(149	)		(140	)		(136	)

After-tax interest expense	$	234		$	221		$	224

The increase in interest expense in 2011 compared to 2010 primarily reflects higher average borrowings following the issuance of $1.25 billion of 30-year fixed-rate public notes in August 2010. Capitalized interest increased in 2011 due to the sanctioning of the Tubular Bells project. Interest expense was comparable in 2010 and 2009. After-tax interest expense in 2012 is expected to be in the range of $245 million to $255 million.

Consolidated Sales and Cost of Products Sold

Sales and other operating revenues totaled $38,466 million in 2011, $33,862 million in 2010 and $29,614 million in 2009. The increase in Sales and other operating revenues of 14% year-on-year from 2009 to 2011 is primarily due to higher crude oil and refined petroleum product selling prices, partially offset by lower crude oil and refined petroleum product sales volumes.

The increase in Cost of products sold each year principally reflects higher prices for purchased refined petroleum products.

Liquidity and Capital Resources

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


	2011			2010
	(Millions of dollars)
Cash and cash equivalents	$	351		$	1,608
Short-term debt and current maturities of long-term debt	$	52		$	46
Total debt	$	6,057		$	5,583
Total equity	$	18,592		$	16,809
Debt to capitalization ratio*		24.6	%		24.9	%

*	Total debt as a percentage of the sum of total debt plus equity.

Cash Flows

The following table sets forth a summary of the Corporation’s cash flows for the years ended December 31:


	2011			2010			2009
	(Millions of dollars)
Net cash provided by (used in):
Operating activities	$	4,984		$	4,530		$	3,046
Investing activities		(6,566	)		(5,259	)		(2,924	)
Financing activities		325			975			332

Net increase (decrease) in cash and cash equivalents	$	(1,257	)	$	246		$	454

Operating Activities: Net cash provided by operating activities amounted to $4,984 million in 2011 compared with $4,530 million in 2010, reflecting higher operating earnings partially offset by a period over period increase in the use of cash from changes in operating assets and liabilities of $412 million. Operating cash flow increased to $4,530 million in 2010 from $3,046 million in 2009 principally reflecting higher earnings.

Investing Activities: The following table summarizes the Corporation’s capital expenditures for the years ended December 31:


	2011		2010		2009
	(Millions of dollars)
Exploration and Production
Exploration	$	869	$	552	$	611
Production and development		4,673		2,592		1,927
Acquisitions (including leaseholds)		1,346		2,250		262

		6,888		5,394		2,800
Marketing, Refining and Corporate		118		98		118

Total	$	7,006	$	5,492	$	2,918

Capital expenditures in 2011 included acquisitions of approximately $800 million for 185,000 net acres in the Utica Shale play in eastern Ohio, $214 million for interests in two blocks in the Kurdistan Region of Iraq and $116 million for an additional 4% interest in the South Arne Field in Denmark. Capital expenditures in 2010 included acquisitions of 167,000 net acres in the Bakken oil shale play in North Dakota from TRZ Energy, LLC for $1,075 million in cash and additional interests of 8% and 13% in the Valhall and Hod fields, respectively, for $507 million in cash. Capital expenditures in 2009 included 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. In addition, proceeds from asset sales were $490 million in 2011 and $183 million in 2010.

Financing Activities: During 2011, net proceeds from borrowings on available credit facilities were $422 million. During 2010, net proceeds from borrowings were $1,098 million, including the August 2010 issuance of $1,250 million of 30-year fixed-rate public notes with a coupon of 5.6% scheduled to mature in 2041. The proceeds were used to purchase additional acreage in the Bakken and additional interests in the Valhall and Hod fields. In January 2010, the Corporation completed the repurchase of the remaining $116 million of fixed-rate public notes that were scheduled to mature in 2011.

Total common stock dividends paid were $136 million in 2011 and $131 million in 2010 and 2009. The Corporation received net proceeds from the exercise of stock options, including related income tax benefits of $88 million, $54 million and $18 million in 2011, 2010 and 2009, respectively.

Future Capital Requirements and Resources

The Corporation anticipates investing a total of approximately $6.8 billion in capital and exploratory expenditures during 2012, substantially all of which is targeted for E&P operations. The Corporation expects to fund its 2012 operations, including capital expenditures, its share of HOVENSA financial support totaling $487 million, dividends, pension contributions and required debt repayments, with existing cash on-hand, cash flows from operations including the effect of hedging, proceeds from asset sales and its available credit facilities. Crude oil and natural gas prices 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, 2011:


	Expiration Date	Capacity		Borrowings		Letters of Credit Issued		Total Used		Available Capacity
		(Millions of dollars)
Revolving credit facility	April 2016	$	4,000	$	—	$	173	$	173	$	3,827
Asset-backed credit facility	July 2012 (a)		525		350		—		350		175
Committed lines	Various (b)		2,675		—		1,063		1,063		1,612
Uncommitted lines	Various (b)		562		100		462		562		—

Total		$	7,762	$	450	$	1,698	$	2,148	$	5,614

(a)

Total capacity of $1 billion subject to the amount of eligible receivables posted as collateral.

(b)

Committed and uncommitted lines have expiration dates through 2014.

In April 2011, the Corporation entered into a new $4 billion syndicated revolving credit facility that matures in April 2016. This facility, which replaced a $3 billion facility that was scheduled to mature in May 2012, can be used for borrowings and letters of credit. Borrowings on the facility bear interest at 1.25% above the London Interbank Offered Rate. A facility fee of 0.25% per annum is also 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 covenants that establish restrictions on the amount of total borrowings and secured debt are consistent with the previous facility.

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 billion subject to the availability of sufficient levels of eligible receivables. At December 31, 2011, outstanding borrowings under this facility of $350 million were collateralized by a total of $947 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 statement filed with the SEC under which it may issue additional debt securities, warrants, common stock or preferred stock. Promptly after filing this report, as a result

of the Corporation’s existing shelf registration expiring on February 26, 2012, the Corporation anticipates filing a new shelf registration statement under the Securities Act of 1933, as amended, under which it may issue, among other things, additional debt securities, warrants, common stock or preferred stock.

The Corporation’s long-term debt agreements contain a financial covenant that restricts the amount of total borrowings and secured debt. At December 31, 2011, the Corporation is permitted to borrow up to an additional $24.9 billion for the construction or acquisition of assets. The Corporation has the ability to borrow up to an additional $4.5 billion of secured debt at December 31, 2011.

The Corporation’s $1.7 billion in letters of credit outstanding at December 31, 2011 were primarily issued to satisfy margin requirements. See also Note 17, Risk Management and Trading Activities in the notes to the Consolidated Financial Statements.

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 with a stable outlook 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, 2011:


			Payments Due by Period
	Total		2012		2013 and 2014		2015 and 2016		Thereafter
	(Millions of dollars)
Total debt*	$	6,057	$	52	$	386	$	459	$	5,160
Operating leases		3,210		531		1,195		320		1,164
Purchase obligations
Supply commitments		8,131		7,187		782		149		13
Capital expenditures and other investments		3,045		1,640		873		257		275
Operating expenses		3,039		1,637		829		204		369
Other long-term liabilities		3,327		290		556		463		2,018

*	At December 31, 2011, the Corporation’s debt bears interest at a weighted average rate of 6.8%.

Supply commitments include term purchase agreements at market prices for a portion of the 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 petroleum 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 $6.8 billion capital investment program for 2012 that was contractually committed at December 31, 2011. 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 in the Consolidated Balance Sheet at December 31, 2011, including asset retirement obligations, pension plan liabilities and estimates for uncertain income tax positions.

During 2011, the Corporation entered into a lease agreement for a floating production system and related support activities for the Tubular Bells Field. Payments under this five year contract, which total approximately $420 million and are expected to commence by mid-2014, are included in Capital expenditures and other investments in the contractual obligations table above. The Corporation also has a tolling agreement with Bayonne Energy Center, LLC (BEC) (Hess 50%), a joint venture formed to generate electricity for sale into the

New York City market. Under the tolling arrangement, the Corporation will pay its share of a predetermined monthly amount to BEC following the start up of plant operations, which is expected in mid-2012. Estimated payments through 2027, which total approximately $415 million, are included in Operating expenses in the contractual obligations table.

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 has a contingent purchase obligation to acquire the remaining interest in WilcoHess, a retail gasoline station joint venture. This contingent obligation, which expires in April 2014, was approximately $205 million at December 31, 2011.

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, 2011 as shown below (in millions of dollars):


Letters of credit	$	67
Guarantees		15

	$	82

Off-balance Sheet Arrangements

The Corporation has leveraged leases not included in its Consolidated Balance Sheet, primarily related to retail gasoline stations that the Corporation operates. The net present value of these leases is $388 million at December 31, 2011 compared with $394 million at December 31, 2010. If these leases were included as debt, the Corporation’s December 31, 2011 debt to capitalization ratio would increase to 25.7% from 24.6%.

See also Note 18, Guarantees and Contingencies in the notes to the Consolidated Financial Statements.

Foreign Operations

The Corporation conducts exploration and production activities outside the United States, principally in Algeria, Australia, Azerbaijan, Brazil, Brunei, China, Denmark, Egypt, Equatorial Guinea, France, Ghana, Indonesia, the Kurdistan region of Iraq, 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 in the Corporation’s Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income. 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. In production operations, costs of injected CO₂ for tertiary recovery are expensed as incurred.

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 operational 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 engages 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 annually in the fourth quarter or when events or circumstances indicate that the carrying amount of the goodwill may not be recoverable. The goodwill test is conducted at a reporting unit level, which is defined in accounting standards as an operating segment or one level

below an operating segment. The reporting unit or units to be used in an evaluation and measurement of goodwill for impairment testing are determined from a number of factors, including the manner in which the business is managed. The Corporation has concluded that the E&P segment is the reporting unit for the purposes of testing goodwill for impairment, since the E&P segment is managed globally by one segment manager who allocates financial and technical resources globally and reviews operating results at the segment level. Accordingly, the Corporation expects that the benefits of goodwill will be recovered through the operations of that segment.

If any of the E&P segment components, such as our financial reporting regions (United States, Europe, Africa and Asia) were considered to be reporting units, an analysis would be performed to determine if these components were economically similar as defined in the accounting standard for goodwill (ASC 350-20-35). If components are economically similar, that guidance requires that those components be aggregated and deemed a single reporting unit.

While the Corporation believes that the E&P segment is the reporting unit because of the manner in which the business is managed, it also evaluated the required aggregation criteria specified in the accounting standard for segment reporting (ASC 280-10-50-11) and determined that its components are economically similar for the following reasons:

•

The Corporation operates its exploration and production segment as a single, global business.

•

Each component produces oil and gas.

•

The exploration and production processes are similar in each component.

•

The methods used by each component to market and distribute oil and gas are similar.

•

Customers of each component are similar.

•

The components share technical resources and support services.

If the Corporation reorganized its exploration and production business such that there was more than one reporting unit, goodwill may be assigned to two or more reporting units.

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 E&P 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.

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 may have occurred. The fair value measurement used in the impairment assessment is based on quoted market prices, where available, or other valuation techniques, including discounted cash flows. Differences between the carrying value of the Corporation’s equity investments and its equity in the net assets of the affiliate that result from impairment charges are amortized over the remaining useful life of the affiliate’s fixed assets.

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 available carryforward periods for net operating losses and credit carryforwards, temporary differences, the availability of tax planning strategies, the existence of appreciated assets and estimates of future taxable income 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 as appropriate. 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 also records certain nonfinancial assets and liabilities at fair value when required by generally accepted accounting principles. These fair value measurements are recorded in connection with business combinations, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments or goodwill.

The Corporation determines fair value in accordance with the FASB fair value measurements accounting standard which established 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 is based on the lowest significant input level within this fair value hierarchy.

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 and other unobservable data 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 petroleum

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-related 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 Consolidated 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 in the Consolidated 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.

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.

Over the last several years, many refineries 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 the New Source Review regulations that require permits and new emission controls in certain circumstances and other regulations that impose emissions control requirements. In January 2011, HOVENSA signed a consent decree with the EPA to resolve its claims. Under the terms of the Consent Decree, HOVENSA agreed to pay a penalty of approximately $5 million and spend approximately $700 million over the next 10 years to install equipment and implement additional operating procedures at the HOVENSA refinery to reduce emissions. In addition, the Consent Decree requires HOVENSA to spend approximately $5 million to fund an environmental project to be determined at a later date by the Virgin Islands and $500,000 to assist the Virgin Islands Water and Power Authority with monitoring. However, as a result of HOVENSA’s decision to shut down its refinery, which was announced in January 2012, HOVENSA believes that it will not be required to make material capital expenditures pursuant to this consent decree. The Corporation believes that it will also enter into a consent decree with the EPA in the near future to resolve these matters as they relate to its Port Reading refinery facility, which is not expected to have a material adverse impact on the financial condition, results of operations or cash flows of the Corporation.

The Corporation produces and distributes fuel oils in the United States. Many states and localities are adopting requirements that mandate a lower sulfur content of fuel oils and restrict the types of fuel oil sold within their jurisdictions. These proposals could require capital expenditures by the Corporation for its Port Reading refining facility to meet the required sulfur content standards or other changes in the marketing of fuel oils and affect the profitability of that facility.

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 expenses when the future costs are probable and reasonably estimable. At year-end 2011, the Corporation’s reserve for estimated remediation liabilities was approximately $60 million. The Corporation expects that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. The Corporation’s remediation spending was $19 million in 2011, $13 million in 2010 and $11 million in 2009. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, other than for the low sulfur requirements, were approximately $95 million in 2011, $85 million in 2010 and $50 million in 2009.

Forward-looking Information

Certain sections of this Annual Report on Form 10-K, including Business and Properties, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures about Market Risk, include 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, which include forward-looking information. These sections typically include statements with words such as “anticipate”, “estimate”, “expect”, “forecast”, “guidance”, “could”, “may”, “should”, “would” or similar words, indicating that future outcomes are uncertain. 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. For more information regarding the factors that may cause the Corporation’s results to differ from these statements, see Item 1A. Risk Factors Related to Our Business and Operations.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

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 petroleum products and electricity, as well as to changes in interest rates and foreign currency values. In the disclosures that follow, risk management activities are referred to as energy marketing and corporate risk management activities. The Corporation also has trading operations, principally through a 50% voting interest in a consolidated partnership that trades energy-related commodities, securities and derivatives. These activities are also exposed to commodity risks primarily related to the prices of crude oil, natural gas and refined petroleum 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 are reported on a daily basis 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 and monitoring foreign exchange rate and interest rate hedging programs.

The Corporation uses value at risk to monitor and control commodity risk within its risk management and trading activities. The value at risk model uses historical simulation and the results represent the potential loss in fair value over one day at a 95% confidence level. The model captures both first and second order sensitivities for options. 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:

•

Forward Commodity Contracts: The Corporation enters into contracts for the forward purchase and sale of commodities. At settlement date, the notional value of the contract is exchanged for physical delivery of the commodity. Forward contracts that are deemed normal purchase and sale contracts are excluded from the quantitative market risk disclosures.

•

Forward Foreign Exchange Contracts: The Corporation enters into forward contracts primarily for the British Pound and the Thai Baht, which commit the Corporation to buy or sell a fixed amount of these currencies at a predetermined exchange rate on a future date.

•

Exchange Traded Contracts: The Corporation uses exchange traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position limits.

•

Swaps: The Corporation uses financially settled swap contracts with third parties as part of its risk management and trading activities. Cash flows from swap contracts are determined based on underlying commodity prices or interest rates and are typically settled over the life of the contract.

•

Options: Options on various underlying energy commodities include exchange traded and third party contracts and have various exercise periods. As a seller of options, the Corporation receives a premium at the outset and bears the risk of unfavorable changes in the price of the commodity underlying the option. As a purchaser of options, the Corporation pays a premium at the outset and has the right to participate in the favorable price movements in the underlying commodities.

•

Energy Securities: Energy securities include energy-related equity or debt securities issued by a company or government or related derivatives on these securities.

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, refined petroleum products 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 has outstanding foreign exchange contracts used to reduce its exposure to fluctuating foreign exchange rates for various currencies, including the British Pound and the Thai Baht. At December 31, 2011, the Corporation had a payable for foreign exchange contracts maturing in 2012 with a fair value of $14 million. The change in fair value of the foreign exchange contracts from a 10% strengthening of the U.S. Dollar exchange rate is estimated to be a loss of approximately $89 million at December 31, 2011.

The Corporation’s outstanding long-term debt of $6,040 million has a fair value of $7,317 million at December 31, 2011. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $247 million at December 31, 2011.

Following is the value at risk for the Corporation’s energy marketing and risk management commodity derivatives activities, excluding foreign exchange and interest rate derivatives described above:


	2011		2010
	(Millions of dollars)
At December 31	$	94	$	5
Average		30		5
High		94		6
Low		8		4

The increase in the value at risk for the Corporation’s energy marketing and risk management commodity derivatives activities in 2011 primarily reflects additional Brent crude oil cash flow hedge positions as described in Note 17, Risk Management and Trading Activities in the notes to the Consolidated Financial Statements.

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:


	2011		2010
	(Millions of dollars)
At December 31	$	4	$	14
Average		11		14
High		16		15
Low		4		12

The information that follows represents 100% of the trading partnership and the Corporation’s proprietary trading accounts. Derivative trading transactions are marked-to-market and unrealized gains or losses are recognized currently in earnings. Gains or losses from sales of physical products are recorded at the time of sale. Net realized gains on trading activities amounted to $44 million in 2011 and $375 million in 2010. The following table provides an assessment of the factors affecting the changes in fair value of financial instruments and derivative commodity contracts used in trading activities:


	2011			2010
	(Millions of dollars)
Fair value of contracts outstanding at January 1	$	94		$	110
Change in fair value of contracts outstanding at the beginning of the year and still outstanding at the end of the year		(69	)		10
Reversal of fair value for contracts closed during the year		9			(233	)
Fair value of contracts entered into during the year and still outstanding		(120	)		207

Fair value of contracts outstanding at December 31	$	(86	)	$	94

The following table summarizes the sources of net asset (liability) fair values of financial instruments and derivative commodity contracts by year of maturity used in the Corporation’s trading activities at December 31, 2011:


	Total			2012			2013			2014			2015 and Beyond
	(Millions of dollars)
Source of fair value
Level 1	$	(45	)	$	(31	)	$	(3	)	$	(1	)	$	(10	)
Level 2		285			276			36			(3	)		(24	)
Level 3		(326	)		(325	)		(60	)		30			29

Total	$	(86	)	$	(80	)	$	(27	)	$	26		$	(5	)

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:


	2011		2010
	(Millions of dollars)
Investment grade determined by outside sources	$	389	$	314
Investment grade determined internally*		304		272
Less than investment grade		89		48

Fair value of net receivables outstanding at December 31	$	782	$	634

*	Based on information provided by counterparties and other available sources.

Item 8.

Financial Statements and Supplementary Data

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS AND SCHEDULE


	Page Number
Management’s Report on Internal Control over Financial Reporting		44
Reports of Independent Registered Public Accounting Firm		45
Consolidated Balance Sheet at December 31, 2011 and 2010		47
Statement of Consolidated Income for each of the three years in the period ended December 31, 2011		48
Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2011		49
Statement of Consolidated Equity and Comprehensive Income for each of the three years in the period ended December 31, 2011		50
Notes to Consolidated Financial Statements		51
Supplementary Oil and Gas Data		85
Quarterly Financial Data		94
Schedule* II — Valuation and Qualifying Accounts		102
Financial Statements of HOVENSA L.L.C. as of December 31, 2011		103

*	Schedules other than Schedule II have been omitted because of the absence of the conditions under which they are required or because the required information is presented in the financial statements or the notes thereto.

Management’s Report on Internal Control over Financial Reporting

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, 2011.

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, 2011, as stated in their report, which is included herein.

/s/ John P. Rielly

/s/ John B. Hess

John P. Rielly

Senior Vice President and

Chief Financial Officer

John B. Hess

Chairman of the Board and

Chief Executive Officer

February 27, 2012

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Hess Corporation

We have audited Hess Corporation’s internal control over financial reporting as of December 31, 2011, 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, 2011 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, 2011 and 2010, 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, 2011 of Hess Corporation and consolidated subsidiaries, and our report dated February 27, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG, LLP

February 27, 2012

New York, New York

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Hess Corporation

We have audited the accompanying consolidated balance sheet of Hess Corporation and consolidated subsidiaries (the “Corporation”) as of December 31, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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.

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, 2011, 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 27, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG, LLP

February 27, 2012

New York, New York

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


	December 31,
	2011			2010
	(Millions of dollars; thousands of shares)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	351		$	1,608
Accounts receivable
Trade		4,761			4,478
Other		250			240
Inventories		1,423			1,452
Other current assets		1,554			1,002

Total current assets		8,339			8,780

INVESTMENTS IN AFFILIATES		384			443

PROPERTY, PLANT AND EQUIPMENT
Total — at cost		39,710			35,703
Less reserves for depreciation, depletion, amortization and lease impairment		14,998			14,576

Property, plant and equipment — net		24,712			21,127

GOODWILL		2,305			2,408
DEFERRED INCOME TAXES		2,941			2,167
OTHER ASSETS		455			471

TOTAL ASSETS	$	39,136		$	35,396


LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	3,712		$	4,274
Accrued liabilities		3,524			2,567
Taxes payable		812			726
Short-term debt and current maturities of long-term debt		52			46

Total current liabilities		8,100			7,613

LONG-TERM DEBT		6,005			5,537
DEFERRED INCOME TAXES		2,843			2,995
ASSET RETIREMENT OBLIGATIONS		1,844			1,203
OTHER LIABILITIES AND DEFERRED CREDITS		1,752			1,239

Total liabilities		20,544			18,587

EQUITY
Hess Corporation Stockholders’ Equity
Common stock, par value $1.00
Authorized — 600,000 shares
Issued: 2011 — 339,976 shares; 2010 — 337,681 shares		340			338
Capital in excess of par value		3,417			3,256
Retained earnings		15,826			14,254
Accumulated other comprehensive income (loss)		(1,067	)		(1,159	)

Total Hess Corporation stockholders’ equity		18,516			16,689
Noncontrolling interests		76			120

Total equity		18,592			16,809

TOTAL LIABILITIES AND EQUITY	$	39,136		$	35,396

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.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME


	Years Ended December 31,
	2011			2010			2009
	(Millions of dollars, except per share data)
REVENUES AND NON-OPERATING INCOME
Sales (excluding excise taxes) and other operating revenues	$	38,466		$	33,862		$	29,614
Income (loss) from equity investment in HOVENSA L.L.C.		(1,073	)		(522	)		(229	)
Gains on asset sales		446			1,208			—
Other, net		32			65			184

Total revenues and non-operating income		37,871			34,613			29,569

COSTS AND EXPENSES
Cost of products sold (excluding items shown separately below)		26,774			23,407			20,961
Production expenses		2,352			1,924			1,805
Marketing expenses		1,069			1,021			1,008
Exploration expenses, including dry holes and lease impairment		1,195			865			829
Other operating expenses		171			213			183
General and administrative expenses		702			662			647
Interest expense		383			361			360
Depreciation, depletion and amortization		2,406			2,317			2,200
Asset impairments		358			532			54

Total costs and expenses		35,410			31,302			28,047

INCOME BEFORE INCOME TAXES		2,461			3,311			1,522
Provision for income taxes		785			1,173			715

NET INCOME	$	1,676		$	2,138		$	807
Less: Net income (loss) attributable to noncontrolling interests		(27	)		13			67

NET INCOME ATTRIBUTABLE TO HESS CORPORATION	$	1,703		$	2,125		$	740

BASIC NET INCOME PER SHARE	$	5.05		$	6.52		$	2.28
DILUTED NET INCOME PER SHARE	$	5.01		$	6.47		$	2.27
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (DILUTED)		339.9			328.3			326.0

See accompanying notes to consolidated financial statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS


	Years Ended December 31,
	2011			2010			2009
	(Millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,676		$	2,138		$	807
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		2,406			2,317			2,200
(Income) loss from equity investment in HOVENSA L.L.C.		1,073			522			229
Asset impairments		358			532			54
Exploratory dry hole costs		438			237			267
Lease impairment		301			266			231
Stock compensation expense		104			112			128
Gains on asset sales		(446	)		(1,208	)		—
Provision (benefit) for deferred income taxes		(623	)		(495	)		(438	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(243	)		(760	)		320
(Increase) decrease in inventories		4			(16	)		(137	)
Increase (decrease) in accounts payable and accrued liabilities		544			1,141			(542	)
Increase (decrease) in taxes payable		46			95			(81	)
Changes in other assets and liabilities		(654	)		(351	)		8

Net cash provided by operating activities		4,984			4,530			3,046

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(7,006	)		(5,492	)		(2,918	)
Proceeds from asset sales		490			183			—
Other, net		(50	)		50			(6	)

Net cash used in investing activities		(6,566	)		(5,259	)		(2,924	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) of debt with maturities of 90 days or less		100			—			(850	)
Debt with maturities of greater than 90 days
Borrowings		422			1,278			1,991
Repayments		(100	)		(180	)		(694	)
Cash dividends paid		(136	)		(131	)		(131	)
Noncontrolling interests, net		(49	)		(46	)		(2	)
Employee stock options exercised, including income tax benefits		88			54			18

Net cash provided by financing activities		325			975			332

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,257	)		246			454
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		1,608			1,362			908

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	351		$	1,608		$	1,362

See accompanying notes to consolidated financial statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED EQUITY AND COMPREHENSIVE INCOME


	Common Stock		Capital in Excess of Par			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Hess Stockholders’ Equity			Noncontrolling Interests			Total Equity
	(Millions of dollars)
Balance at January 1, 2009	$	326	$	2,347		$	11,642		$	(2,008	)	$	12,307		$	84		$	12,391
Net income							740						740			67			807
Deferred gains (losses) on cash flow hedges, after-tax
Effect of hedge losses recognized in income										963			963			—			963
Net change in fair value of cash flow hedges										(729	)		(729	)		—			(729	)
Change in postretirement plan liabilities, after-tax										(6	)		(6	)		—			(6	)
Change in foreign currency translation adjustment and other										105			105			(5	)		100

Comprehensive income (loss)													1,073			62			1,135
Activity related to restricted common stock awards, net		1		61			—			—			62			—			62
Employee stock options, including income tax benefits		—		73			—			—			73			—			73
Cash dividends declared		—		—			(131	)		—			(131	)		—			(131	)
Noncontrolling interests, net		—		—			—			—			—			(2	)		(2	)

Balance at December 31, 2009		327		2,481			12,251			(1,675	)		13,384			144			13,528

Net income							2,125						2,125			13			2,138
Deferred gains (losses) on cash flow hedges, after-tax
Effect of hedge losses recognized in income										656			656			—			656
Net change in fair value of cash flow hedges										(198	)		(198	)		—			(198	)
Change in postretirement plan liabilities, after-tax										28			28			—			28
Change in foreign currency translation adjustment and other										30			30			1			31

Comprehensive income (loss)													2,641			14			2,655
Common stock issued for acquisition		9		639			—			—			648			—			648
Activity related to restricted common stock awards, net		1		59			—			—			60			—			60
Employee stock options, including income tax benefits		1		105			—			—			106			—			106
Cash dividends declared		—		—			(132	)		—			(132	)		—			(132	)
Noncontrolling interests, net		—		(28	)		10			—			(18	)		(38	)		(56	)

Balance at December 31, 2010		338		3,256			14,254			(1,159	)		16,689			120			16,809

Net income							1,703						1,703			(27	)		1,676
Deferred gains (losses) on cash flow hedges, after-tax
Effect of hedge losses recognized in income										432			432			—			432
Net change in fair value of cash flow hedges										2			2			—			2
Change in postretirement plan liabilities, after-tax										(246	)		(246	)		—			(246	)
Change in foreign currency translation adjustment and other										(96