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, 2010
or
o		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)

 

 

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

 

 

 

 

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

 

 

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

None

 

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

 

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

 

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

 

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

 

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

 

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

 

(Do not check if a smaller reporting company)

 

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

 

The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $14,497,000,000 computed using the outstanding common shares and closing market price on June 30, 2010.

 

At December 31, 2010, there were 337,680,780 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 4, 2011.

 

 

HESS CORPORATION

 

Form 10-K

 

TABLE OF CONTENTS

 

 

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, Colombia, Denmark, Egypt, Equatorial Guinea, France, Ghana, Indonesia, Libya, Malaysia, Norway, Peru, Russia, Thailand, the United Kingdom and the United States. The M&R segment manufactures refined petroleum products and purchases, markets and trades refined petroleum products, natural gas and electricity. The Corporation owns 50% of a refinery joint venture in the United States Virgin Islands. An additional refining facility, terminals and retail gasoline stations, most of which include convenience stores, are located on the East Coast of the United States.

 

Exploration and Production

 

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

 

		Crude Oil,																Total Barrels of
		Condensate &																Oil
		Natural Gas																Equivalent
		Liquids (c)								Natural Gas								(BOE)(a)
		2010				2009				2010				2009				2010				2009
		(Millions of barrels)								(Millions of mcf)								(Millions of barrels)
Developed
United States			180				154				199				205				213				188
Europe(b)			210				171				424				417				281				241
Africa			215				241				54				59				224				251
Asia			22				27				638				864				128				170
			627				593				1,315				1,545				846				850
Undeveloped
United States			124				95				81				101				138				112
Europe(b)			256				159				295				225				305				197
Africa			55				73				9				12				56				75
Asia			42				47				898				938				192				203
			477				374				1,283				1,276				691				587
Total
United States			304				249				280				306				351				300
Europe(b)			466				330				719				642				586				438
Africa			270				314				63				71				280				326
Asia			64				74				1,536				1,802				320				373
			1,104				967				2,598				2,821				1,537				1,437

 

 

 

 

		Crude Oil and								Total Barrels of
		Natural Gas Liquids				Natural Gas				Oil Equivalent (BOE)
		(Millions of barrels)				(Millions of mcf)				(Millions of barrels)
Developed			97				157				123
Undeveloped			167				247				208
Total			264				404				331

 

 

On a barrel of oil equivalent (boe) basis, 45% of the Corporation’s worldwide proved reserves are undeveloped at December 31, 2010 (41% at December 31, 2009). Proved reserves held under production sharing contracts at December 31, 2010 totaled 15% of crude oil and natural gas liquids and 51% of natural gas reserves (24% and 57%, respectively, at December 31, 2009).

 

The Securities and Exchange Commission (SEC) revised its oil and gas reserve estimation and disclosure standards effective December 31, 2009. See the Supplementary Oil and Gas Data on pages 88 through 97 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:

 

		2010				2009				2008
Crude oil (thousands of barrels per day)
United States
Offshore			52				39				15
Onshore			23				21				17
			75				60				32
Europe
United Kingdom			19				21				29
Norway*			16				13				16
Denmark			11				12				11
Russia			42				37				27
			88				83				83
Africa
Equatorial Guinea			69				70				72
Algeria			11				14				15
Gabon			10				14				14
Libya			23				22				23
			113				120				124
Asia
Azerbaijan			7				8				7
Other			6				8				6
			13				16				13
Total			289				279				252
Natural gas liquids (thousands of barrels per day)
United States
Offshore			7				4				3
Onshore			7				7				7
			14				11				10
Europe*			3				3				4
Asia			1				—				—
Total			18				14				14

		2010				2009				2008
Natural gas (thousands of mcf per day)
United States
Offshore			70				55				37
Onshore			38				38				41
			108				93				78
Europe
United Kingdom			93				118				223
Norway*			29				21				22
Denmark			12				12				10
			134				151				255
Asia and Other
Joint Development Area of Malaysia/Thailand (JDA)			282				294				185
Thailand			85				85				87
Indonesia			50				65				82
Other			10				2				2
			427				446				356
Total			669				690				689
Barrels of oil equivalent (per day)**			418				408				381

 

 

 

A description of our significant E&P operations follows:

 

United States

 

At December 31, 2010, 23% of the Corporation’s total proved reserves were located in the United States. During 2010, 29% 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 properties offshore in the Gulf of Mexico, as well as onshore properties 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 pursuing water injection and additional development drilling opportunities. However, development and exploration activities are currently being affected by the uncertain regulatory environment in the Gulf of Mexico. See Gulf of Mexico Update on page 12.

 

At the Pony project on Green Canyon Block 468 (Hess 100%), the Corporation has signed a non-binding agreement in principle with the owners on adjacent Green Canyon Block 512 that outlines a proposal to jointly develop the Pony and Knotty Head fields. Negotiation of a joint operating agreement and planning for field development are underway. The agreement in principle provides that Hess will be operator of the joint development. The Corporation also commenced and subsequently suspended drilling the Pony 3 appraisal well on Green Canyon Block 469 in 2010. The Corporation is planning to resume drilling in 2011 contingent upon receipt of necessary permits.

 

In the third quarter of 2010, the Corporation acquired an additional 20% interest in the Tubular Bells oil and gas field in the Gulf of Mexico. The Corporation now has a 40% working interest in the field and is operator. Engineering and design work for the field development progressed during 2010 and will continue in 2011.

 

At December 31, 2010, the Corporation had interests in 306 blocks in the Gulf of Mexico, of which 272 were exploration blocks comprising 1,069,000 net undeveloped acres, with an additional 78,000 net acres held for production and development operations.

Onshore:  In North Dakota, the Corporation holds more than 900,000 net acres in the Bakken oil shale play (Bakken). In December 2010, the Corporation acquired approximately 85,000 net acres in the Bakken through the purchase of American Oil & Gas Inc. (American Oil & Gas) through the issuance of approximately 8.6 million shares of the Corporation’s stock. Further, in December 2010, the Corporation acquired an additional 167,000 net acres in the Bakken from TRZ Energy, LLC for $1,075 million in cash. The Corporation is currently operating 18 drilling rigs in the Bakken and is expanding production and export facilities to accommodate future production growth. In 2011, the Corporation plans to invest $1.8 billion for drilling and infrastructure in the Bakken.

 

In Texas, the Corporation holds a 34% interest in the Seminole-San Andres Unit and is operator. The Corporation is developing a part of this producing field using tertiary CO₂ flooding operations.

 

During 2010, the Corporation acquired approximately 90,000 net acres in the Eagle Ford shale formation in Texas. The Corporation plans to drill an initial six exploration wells, which will be followed by 12 appraisal wells. Exploration drilling commenced in the fourth quarter of 2010.

 

In the Marcellus gas shale formation in Pennsylvania, the Corporation is operator and holds a 100% interest on approximately 53,000 net acres and holds a 50% non-operated interest in approximately 38,000 net acres. There is currently a drilling moratorium in the Delaware River Basin area, where the majority of the Corporation’s acreage is located. The moratorium is expected to remain in place until the Delaware River Basin Commission establishes new drilling regulations.

 

Europe

 

At December 31, 2010, 38% of the Corporation’s total proved reserves were located in Europe (United Kingdom 6%, Norway 22%, Denmark 3% and Russia 7%). During 2010, 30% of the Corporation’s crude oil and natural gas liquids production and 20% of its natural gas production were from European operations.

 

United Kingdom:  Production of crude oil and natural gas liquids from the United Kingdom North Sea was principally from the Corporation’s non-operated interests in the Nevis (Hess 27%), Bittern (Hess 28%), Schiehallion (Hess 16%) and Beryl (Hess 22%) fields. Natural gas production from the United Kingdom was primarily from the Bacton Area (Hess 23%), Easington Catchment Area (Hess 30%), Everest (Hess 19%), Beryl (Hess 22%), Nevis (Hess 27%) and Lomond (Hess 17%) fields. The Corporation also has an 18% interest in the Central Area Transmission System (CATS) pipeline and interests in the Atlantic (Hess 25%) and Cromarty (Hess 90%) fields.

 

In September 2010, the Corporation disposed of all of its interests in the Clair Field as part of an exchange for additional interests in the Valhall and Hod fields in Norway as further described below.

 

In February 2011, the Corporation completed the previously announced sale of a package of natural gas producing assets in the United Kingdom North Sea including its interests in the Easington Catchment Area, the Bacton Area, the Everest Field and the Lomond Field for approximately $350 million, after closing adjustments. The sale of the Corporation’s interest in the CATS pipeline is expected to close in the second quarter of 2011.

 

Norway:  Substantially all of the 2010 Norwegian production was from the Corporation’s interest in the Valhall Field (Hess 64%). The Corporation also holds an interest in the Hod (Hess 63%), Snohvit (Hess 3%) and Snorre (Hess 1%) fields. All four of the Corporation’s Norwegian field interests are located offshore.

 

In September 2010, the Corporation exchanged 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. Also in September 2010, the Corporation completed the acquisition of an additional 8% interest in the Valhall Field and 13% interest in the Hod Field for $507 million. After these transactions, the Corporation’s interests in the Valhall and Hod fields are now 64% and 63%, respectively.

 

A field redevelopment for Valhall commenced in 2007 and the Valhall Flank Gas Lift project was sanctioned in 2009. In 2010, the operator continued work on these projects, which are expected to be completed and commissioned in 2011. In 2011, further drilling is planned for Valhall, which will include the addition of a jack-up rig during the second half of the year.

Denmark:  Crude oil and natural gas production comes from the Corporation’s operated interest in the South Arne Field (Hess 58%). In 2010, the Corporation drilled two new production wells and sanctioned an additional development phase at South Arne, which will include design, construction and installation of two new platforms and related infrastructure.

 

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 2010, the Corporation acquired an additional 5% interest in its subsidiary, increasing its ownership to 85%. As of December 31, 2010, this subsidiary had exploration and production rights in 18 license areas in the Samara and Ulyanovsk territories.

 

France:  In 2010, the Corporation entered into 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 Paris Basin acreage. An initial six exploration well program is scheduled to begin in 2011, with the first well expected to spud in the first half of 2011.

 

Africa

 

At December 31, 2010, 18% of the Corporation’s total proved reserves were located in Africa (Equatorial Guinea 6%, Algeria 1% and Libya 11%). During 2010, 37% of the Corporation’s crude oil and natural gas liquids production was from African operations. In September 2010, the Corporation disposed of all of its interests in Gabon as part of the exchange for additional interests in the Valhall and Hod fields in Norway.

 

Equatorial Guinea:  The Corporation is the operator and owns an interest in Block G (Hess 85%) which contains the Ceiba Field and Okume Complex. In 2010, a 4D seismic survey was acquired covering the Okume Complex and the Ceiba Field. This seismic data will be processed and evaluated in 2011 in preparation for potential further development drilling.

 

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.

 

Libya:  The Corporation, in conjunction with its Oasis Group partners, has oil and gas production operations in the Waha concessions in Libya (Hess 8%). The Corporation also owns a 100% interest in offshore exploration Area 54 in the Mediterranean Sea, where a successful exploration well was drilled in 2008. In 2009, the Corporation successfully drilled a down-dip appraisal well. In 2010, the Corporation received a five year extension to the Area 54 license.

 

Egypt:  The Corporation has an interest in the West Mediterranean Block 1 concession (West Med Block) (Hess 55%). In September 2010, the Corporation recorded an after-tax charge of $347 million to fully impair the carrying value of its interest in the West Med Block and to expense a previously capitalized well. See further discussion in Management’s Discussion and Analysis of Financial Condition and Results of Operations on page 29. The Corporation also owns a 100% interest in Block 1 offshore Egypt in the North Red Sea. The Corporation spud an exploration well on the North Red Sea block in late December 2010, the completion of which may be delayed by the current political unrest in Egypt. In December 2010, the Corporation entered a farm-out agreement that will, subject to government approval, reduce its interest in the block from 100% to 80%.

 

Ghana:  The Corporation holds a 100% interest in the Deepwater Tano Cape Three Points License. In 2010, the Corporation acquired additional 3D seismic data and plans to drill a second exploration well on this block in 2011.

 

Asia

 

At December 31, 2010, 21% of the Corporation’s total proved reserves were located in the Asia region (JDA 9%, Indonesia 6%, Thailand 3%, Azerbaijan 2% and Malaysia 1%). During 2010, 4% of the Corporation’s crude oil and natural gas liquids production and 64% 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 will continue development of the block with further drilling and construction of additional platform facilities.

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 an interest in Block PM302 (Hess 50%) and Belud — Block SB302 (Hess 40%). Through December 31, 2010 the Corporation has drilled two wells on Block SB302 which were natural gas discoveries. Technical and commercial evaluations are underway to assess the development alternatives for this block.

 

Indonesia:  The Corporation’s natural gas production in Indonesia primarily comes from its interests offshore in the Ujung Pangkah project (Hess 75%), and the Natuna A Field (Hess 23%). In 2010, the Corporation installed a new wellhead platform at Ujung Pangkah and will install a new central processing platform in 2011 to expand oil and water handling capacity. At the Natuna A Field the operator is constructing a second wellhead platform and a central processing platform, which is expected to be placed in service in 2011. The Corporation also holds a 100% working interest in the offshore Semai V Block, where it plans to drill three exploration wells beginning in 2011. The Corporation owns a 100% working interest in the offshore South Sesulu Block and a 49% interest in the West Timor Block. In 2010, the Corporation sold its interest in the Jambi Merang onshore natural gas development project.

 

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

 

Azerbaijan:  The Corporation has an interest in the Azeri-Chirag-Guneshli (ACG) fields (Hess 3%) in the Caspian Sea and also owns an interest in the Baku-Tiblisi-Ceyhan oil transportation pipeline (Hess 2%). In 2010, the Corporation sanctioned the Chirag Oil Development project at ACG. This project includes construction and installation of a production, drilling and living-quarters platform and further development drilling.

 

Brunei:  The Corporation has a 14% interest in Block CA-1 (previously known as Block J). The Corporation expects the operator to begin exploration drilling in the second half of 2011.

 

China:  The Corporation has signed a joint study agreement with China National Petroleum Corporation and two joint study agreements with Sinopec to evaluate unconventional oil and gas resource opportunities in China.

 

Other Exploration Areas

 

Australia:  The Corporation holds a 100% interest in an exploration license covering 780,000 acres in the Carnarvon basin offshore Western Australia (WA-390-P Block). The Corporation has drilled all of the 16 commitment wells on the block, 13 of which were natural gas discoveries. In the fourth quarter of 2010, the Corporation commenced an appraisal program that includes further drilling and flow testing certain wells. In November 2010, the Corporation sold its 50% interest in the WA-404-P Block located offshore Western Australia.

 

Brazil:  The Corporation has a 40% interest in block BM-S-22 located offshore Brazil. In early 2011, the operator completed drilling of a third exploration well on this block, which did not encounter commercial quantities of hydrocarbons. See further discussion in Management’s Discussion and Analysis of Financial Condition and Results of Operations on page 23. The Corporation also had an interest in Block BM-ES-30 but reassigned its 30% interest in 2010, pending government approval.

 

Peru:  The Corporation has an interest in Block 64 in Peru (Hess 50%). In 2010, the Corporation successfully drilled a sidetrack to an exploration well on this block. Further evaluation work is planned for 2011.

 

Colombia:  The Corporation has interests in offshore Blocks RC 6 and RC 7 (Hess 30%).

 

Sales Commitments

 

In the E&P segment, the Corporation has no contracts or agreements to sell fixed quantities of its crude oil production. The Corporation has contracts to supply fixed quantities of natural gas, principally relating 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 natural gas sales contract expiring in 2027. There are additional natural gas supply commitments on producing fields in Thailand and Indonesia which currently total approximately 42 million mcf per year under contracts expiring in years 2021 through 2029. The Corporation is also currently committed to supply 7 million mcf per year of natural gas from its

share of production to a liquefied natural gas (LNG) processing facility in Norway under a contract expiring in 2026. The estimated total volume of natural gas subject to sales commitments under these contracts is approximately 2,700 million mcf. The Corporation has not experienced any significant constraints in satisfying the committed quantities under these natural gas sales contracts and it anticipates being able to meet future requirements from available proved and probable reserves. In the United States there are no long-term sales contracts for natural gas production from the E&P segment.

 

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

 

		2010				2009				2008
Average selling prices(a)
Crude oil (per barrel)
United States		$	75.02			$	60.67			$	96.82
Europe(b)			58.11				47.02				78.75
Africa			65.02				48.91				78.72
Asia			79.23				63.01				97.07
Worldwide			66.20				51.62				82.04
Natural gas liquids (per barrel)
United States		$	47.92			$	36.57			$	64.98
Europe(b)			59.23				43.23				74.63
Asia			63.50				46.48				—
Worldwide			50.49				38.47				67.61
Natural gas (per mcf)
United States		$	3.70			$	3.36			$	8.61
Europe(b)			6.23				5.15				9.44
Asia and other			5.93				5.06				5.24
Worldwide			5.63				4.85				7.17
Average production (lifting) costs per barrel of oil equivalent produced(c)
United States		$	12.61			$	13.72			$	18.46
Europe(b)			17.55				15.77				17.12
Africa			11.00				10.93				10.22
Asia			8.16				7.65				8.48
Worldwide			12.61				12.12				13.43

 

 

 

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, 2010

 

		Undeveloped
		Acreage(a)
		Gross				Net
		(In thousands)
United States			3,650				2,478
Europe(c)			2,922				1,260
Africa			9,619				6,282
Asia and other			9,958				5,247
Total(b)			26,149				15,267

 

 

 

Gross and net developed acreage and productive wells at December 31, 2010

 

		Developed
		Acreage
		Applicable to								Productive Wells*
		Productive Wells								Oil								Gas
		Gross				Net				Gross				Net				Gross				Net
		(In thousands)
United States			628				538				1,114				573				61				46
Europe**			1,381				847				289				158				151				31
Africa			9,831				933				905				132				—				—
Asia and other			2,200				630				74				7				468				98
Total			14,040				2,948				2,382				870				680				175

 

 

 

Number of net exploratory and development wells drilled

 

		Net Exploratory												Net Development
		Wells												Wells
		2010				2009				2008				2010				2009				2008
Productive wells
United States			—				—				2				83				44				50
Europe*			1				7				11				18				12				11
Africa			1				1				1				11				23				23
Asia and other			6				8				5				7				12				25
			8				16				19				119				91				109
Dry holes
United States			5				4				—				—				—				1
Europe*			—				—				3				—				—				—
Africa			2				—				2				1				—				—
Asia and other			2				2				1				—				—				—
			9				6				6				1				—				1
Total			17				22				25				120				91				110

 

 

 

Number of wells in process of drilling at December 31, 2010:

 

		Gross				Net
		Wells				Wells
United States			41				17
Europe			11				10
Africa			16				2
Asia and other			12				3
Total			80				32

 

 

Number of net waterfloods and pressure maintenance projects in process of installation at December 31, 2010 — 1

 

 

 

Marketing and Refining

 

Refining

 

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

 

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

 

The following table summarizes capacity and utilization rates for HOVENSA:

 

		Refinery		Refinery Utilization
		Capacity		2010				2009				2008
		(Thousands of
		barrels per day)
Crude		500			78.0%				80.3%				88.2%
Fluid catalytic cracker		150			66.5%				70.2%				72.7%
Coker		58			78.3%				81.6%				92.4%

 

 

In January 2011, HOVENSA announced plans to shut down certain older and smaller processing units on the west side of its refinery, which will reduce the refinery’s crude oil distillation capacity from 500,000 to 350,000 barrels per day, with no impact on the capacity of its coker or FCC unit. This reconfiguration, which is expected to be completed in the first quarter of 2011, is being undertaken to improve efficiency, reliability and competitiveness. In 2010, the Corporation recorded an impairment charge related to its investment in HOVENSA. For discussion of the impairment charge, see Note 4, Refining Joint Venture in the notes to the financial statements on page 59.

 

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

 

Gross crude runs at HOVENSA averaged 390,000 barrels per day in 2010 compared with 402,000 barrels per day in 2009 and 441,000 barrels per day in 2008. The 2010 and 2009 utilization rates for HOVENSA reflect weaker refining margins, higher fuel costs and planned and unplanned maintenance. During the first quarter of 2010, the fluid catalytic cracking unit at HOVENSA was shut down for a scheduled turnaround. The 2008 utilization rates reflect a refinery wide shut down for Hurricane Omar.

 

Port Reading Facility:  The Corporation owns and operates a fluid catalytic cracking facility in Port Reading, New Jersey, with a capacity of 70,000 barrels per day. This facility, which processes residual fuel oil and vacuum

gas oil, operated at a rate of approximately 55,000 barrels per day in 2010 compared with 63,000 barrels per day in 2009 and 64,000 barrels per day in 2008. Substantially all of Port Reading’s production is gasoline and heating oil. During 2010, the Port Reading refining facility was shutdown 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 1,362 HESS^® gasoline stations at December 31, 2010, including stations owned by its WilcoHess joint venture (Hess 44%). Approximately 92% of the gasoline stations are operated by the Corporation or WilcoHess. Of the operated stations, 94% have convenience stores on the sites. Most of the Corporation’s gasoline stations are in New York, New Jersey, Pennsylvania, Florida, Massachusetts, North Carolina and South Carolina.

 

The table below summarizes marketing sales volumes:

 

		2010*				2009*				2008*
Refined Product sales (thousands of barrels per day)
Gasoline			242				236				234
Distillates			120				134				143
Residuals			69				67				56
Other			40				36				39
Total refined product sales			471				473				472
Natural gas (thousands of mcf per day)			2,016				2,010				1,955
Electricity (megawatts round the clock)			4,140				4,306				3,152

 

 

 

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

 

The Corporation has a 50% interest in Bayonne Energy Center, LLC, a joint venture 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 expected to commence in 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.

 

The Corporation is pursuing opportunities for LNG import terminals in Shannon, Ireland and on the East Coast of the United States. In addition, a subsidiary of the Corporation is exploring the development of fuel cell and hydrogen reforming technologies.

 

For additional financial information by segment see Note 18, Segment Information in the notes to the financial statements.

 

Competition and Market Conditions

 

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

Other Items

 

Gulf of Mexico Update:  In April 2010, an accident occurred on the Transocean Deepwater Horizon drilling rig at the BP p.l.c. (BP) operated Macondo prospect in the Gulf of Mexico, resulting in loss of life, the sinking of the rig and a significant crude oil spill. The Corporation was not a participant in the well. As a result of the accident, a temporary drilling moratorium was imposed in the Gulf of Mexico. In October 2010, the drilling moratorium was lifted by the United States Department of the Interior’s Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) provided operators complied with all rules and requirements, including a series of new drilling and safety rules issued by BOEMRE. The Corporation is currently evaluating the impact of these new requirements on its activities in the Gulf of Mexico, as well as seeking approvals for plans and permits submitted in connection with planned activities. However, the new regulatory environment is expected to result in a longer permitting process and higher costs.

 

The moratorium impacted development drilling at the Shenzi Field, in which the Corporation has a 28% interest. A production well that was being drilled was suspended and the drilling of a second production well that was planned for 2010 was postponed. The Corporation estimates that these delays reduced 2010 production by approximately 2,000 barrels of oil equivalent per day (boepd) and will likely reduce 2011 production by approximately 4,000 boepd. In 2010, the Corporation’s only operated drilling rig in the Gulf of Mexico, the Stena Forth, left the Pony project on Green Canyon 469 as part of a preexisting agreement for a one well farm-out of the rig to another operator.

 

In January 2011, the BOEMRE announced that supplementary environmental reviews will not be required of 13 companies to resume work on the 16 wells that were in progress when the moratorium took effect, including the aforementioned suspended Shenzi and Pony wells. However, these projects must comply with the new safety rules and regulations before work can resume. As a result, the Corporation does not anticipate that it will be able to re-commence these operations before the second half of 2011.

 

Additionally, the Corporation has filed Suspension of Operations (SOO) applications with the BOEMRE for several exploration block licenses in the Gulf of Mexico that are due to expire in 2011 and may file additional applications as deemed necessary. These SOO applications seek approval for extension of the lease expiration terms due to circumstances outside the control of the Corporation that have delayed activities required to hold the licenses.

 

Remediation Plans and Procedures:  The Corporation has in place a series of asset-specific emergency response and continuity plans which detail procedures for rapid and effective emergency response and environmental mitigation activities for its global offshore operations. These plans are maintained, reviewed and updated annually to ensure their accuracy and suitability.

 

Where appropriate, plans are reviewed and approved by the relevant host government authorities on a periodic basis. The Corporation has a current oil spill response plan for its Gulf of Mexico operations that has been approved by the BOEMRE. This plan sets forth expectations for response training, drills and capabilities and the strategies, procedures and methods that will be employed 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.

 

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, the Corporation maintains membership contracts with oil spill response organizations to provide coverage for its global drilling and production operations. These organizations are Clean Gulf Associates, National Response Corporation (NRC) and Oil Spill Response (OSR). Clean Gulf Associates is a regional spill response organization for the Gulf of Mexico; NRC and OSR are global response corporations 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 include 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 request these organizations to obtain additional critical response support services, it would provide the funding for such services and seek reimbursement under its insurance coverages 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. It also has representation on the Executive Committee of Clean Gulf Associates and the Board of Directors of OSR, maintaining close associations with these organizations.

 

In light of the recent events in the Gulf of Mexico, the Corporation is participating in a number of industry-wide task forces that are studying better ways to assess the risk of and prevent 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 where 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 $1.9 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 $995 million.

 

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.

 

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 $13 million in 2010 for environmental remediation. 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 13,800 in 2010 and 13,300 in 2009.

 

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.

 

 

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

 

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 influenced by numerous factors beyond our control. Historically these prices have been very volatile. 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. Changes in commodity prices can also have a material impact on collateral and margin requirements under our derivative contracts. In addition, we utilize significant bank credit facilities to support these collateral and margin requirements. An inability to renew or replace such credit facilities as they mature would negatively impact our liquidity.

 

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 revisions based on production performance, purchases or sales of properties, results of future development, prevailing oil and gas prices, production sharing contracts, which may decrease reserves as crude oil and natural gas prices increase, and other factors.

 

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, 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. 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-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. Uncertainty continues to exist as to the conditions under which future drilling in the Gulf of Mexico will occur. However, the new regulatory environment is expected to result 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. Current political unrest in North Africa and the Middle East may 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 risk such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for pollution or other environmental damage. 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 temporary moratoriums and new regulations on such drilling operations that would likely have the effect of delaying and increasing the cost of such operations.

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

 

 

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

 

Over the last several years, many refiners have entered into consent agreements to resolve the United States Environmental Protection Agency’s (EPA) assertions that refining facilities were modified or expanded without complying with New Source Review regulations that require permits and new emission controls in certain circumstances and other regulations that impose emissions control requirements. These consent agreements, which arise out of an EPA enforcement initiative focusing on petroleum refiners and utilities, have typically imposed substantial civil fines and penalties and required (i) significant capital expenditures to install emissions control equipment over a three to eight year time period and (ii) changes to operations which resulted in increased operating costs. The capital expenditures, penalties and supplemental environmental projects for individual

refineries covered by the settlements can vary significantly, depending on the size and configuration of the refinery, the circumstances of the alleged modifications and whether the refinery has previously installed more advanced pollution controls. In January 2011, HOVENSA signed a Consent Decree with EPA to resolve its claims. Under the terms of the Consent Decree, HOVENSA will 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. The Consent Decree has been lodged with the United States District Court for the Virgin Islands and approval is pending. In addition, substantial progress has been made towards resolving this matter for the Port Reading refining facility, which is not expected to have a material adverse impact on the Corporation’s financial position or results of operations.

 

On September 13, 2007, HOVENSA received a Notice Of Violation (NOV) pursuant to section 113(a)(i) of the Clean Air Act (Act) from the EPA finding that HOVENSA failed to obtain proper permitting for the construction and operation of its delayed coking unit in accordance with applicable law and regulations. HOVENSA believes it properly obtained all necessary permits for this project. The NOV states that the EPA has authority to issue an administrative order assessing penalties for violation of the Act. This matter is resolved by the Consent Decree discussed above, provided that the Consent Decree is entered by the court.

 

In December 2006, HOVENSA received a NOV from the EPA alleging non-compliance with emissions limits in a permit issued by the Virgin Islands Department of Planning and Natural Resources (DPNR) for the two process heaters in the delayed coking unit. The NOV was issued in response to a voluntary investigation and submission by HOVENSA regarding potential non-compliance with the permit emissions limits for two pollutants. Any exceedances were minor from the perspective of the amount of pollutants emitted in excess of the limits. This matter is resolved by the Consent Decree discussed above, provided that the Consent Decree is entered by the court.

 

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”). 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 intends to vigorously defend this matter.

 

The Corporation received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the lower Passaic River and NJDEP is also seeking natural resource damages. The directive, insofar as it affects the Corporation, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey now owned by the Corporation. The Corporation and over 70 companies entered into an Administrative Order on Consent with the EPA to study the same contamination. NJDEP has also sued several other companies linked to a facility considered by the State to be the largest contributor to river contamination. In January 2009, these companies added third party defendants, including the Corporation, to that case. In June 2007, the EPA issued a draft study which evaluated six alternatives for early action, with costs ranging from $900 million to $2.3 billion. Based on adverse comments from the Corporation and others, the EPA is reevaluating its alternatives. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given the ongoing studies, remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, the Corporation does not believe that this matter will result in 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.

 

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

 

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

 

The Corporation is from time to time involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. 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 will not have a material adverse effect on the financial condition of the Corporation, although the outcome of such proceedings could be material to the Corporation’s results of operations and cash flows for a particular period depending on, among other things, the level of the Corporation’s net income for such period.

 

 

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:

 

 

 

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:

 

 

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

 

 

Holders

 

At December 31, 2010, there were 5,791 stockholders (based on number of holders of record) who owned a total of 337,680,780 shares of common stock.

 

Dividends

 

Cash dividends on common stock totaled $0.40 per share ($0.10 per quarter) during 2010, 2009 and 2008.

Equity Compensation Plans

 

Following is information on the Registrant’s equity compensation plans at December 31, 2010:

 

 

 

 

See Note 10, Share-Based Compensation, in the notes to the financial statements for further discussion of the Corporation’s equity compensation plans.

 

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

 

 

 

 

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 2010 was $2,125 million compared with $740 million in 2009 and $2,360 million in 2008. Diluted earnings per share were $6.47 in 2010 compared with $2.27 in 2009 and $7.24 in 2008. A table of items affecting comparability between periods is shown on page 25.

 

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 1,537 million barrels of oil equivalent (boe) at December 31, 2010 compared with 1,437 million boe at December 31, 2009 and 1,432 million boe at December 31, 2008.

 

E&P earnings were $2,736 million in 2010, $1,042 million in 2009 and $2,423 million in 2008. Average realized crude oil selling prices were $66.20 per barrel in 2010, $51.62 in 2009, and $82.04 in 2008, including the impact of hedging. Production averaged 418,000 barrels of oil equivalent per day (boepd) in 2010, an increase of 10,000 boepd or 2.5% from 2009. Production averaged 408,000 boepd in 2009, an increase of 27,000 boepd or 7% from 381,000 boepd in 2008. The Corporation estimates that total worldwide production will average between 415,000 and 425,000 boepd in 2011.

 

The following is an update of significant E&P activities during 2010:

 

 

 

Gulf of Mexico Update:  In April 2010, an accident occurred on the Transocean Deepwater Horizon drilling rig at the BP p.l.c. (BP) operated Macondo prospect in the Gulf of Mexico, resulting in loss of life, the sinking of the rig and a significant crude oil spill. The Corporation was not a participant in the well. As a result of the accident, a temporary drilling moratorium was imposed in the Gulf of Mexico. In October 2010, the drilling moratorium was lifted by the United States Department of the Interior’s Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) provided operators complied with all rules and requirements, including a series of new drilling and safety rules issued by BOEMRE. The Corporation is currently evaluating the impact of these new requirements on its activities in the Gulf of Mexico, as well as seeking approvals for plans and permits submitted in connection with planned activities. However, the new regulatory environment is expected to result in a longer permitting process and higher costs.

 

The moratorium impacted development drilling at the Shenzi Field, in which the Corporation has a 28% interest. A production well that was being drilled was suspended and the drilling of a second production well that was planned for 2010 was postponed. The Corporation estimates that these delays reduced 2010 production by approximately 2,000 boepd and will likely reduce 2011 production by approximately 4,000 boepd. In 2010, the Corporation’s only operated drilling rig in the Gulf of Mexico, the Stena Forth, left the Pony project on Green Canyon 469 as part of a preexisting agreement for a one well farm-out of the rig to another operator.

 

In January 2011, the BOEMRE announced that supplementary environmental reviews will not be required of 13 companies to resume work on the 16 wells that were in progress when the moratorium took effect, including the aforementioned suspended Shenzi and Pony wells. However, these projects must comply with the new safety rules and regulations before work can resume. As a result, the Corporation does not anticipate that it will be able to re-commence these operations before the second half of 2011.

 

Additionally, the Corporation has filed Suspension of Operations (SOO) applications with the BOEMRE for several exploration block licenses in the Gulf of Mexico that are due to expire in 2011 and may file additional applications as deemed necessary. These SOO applications seek approval for extension of the lease expiration terms due to circumstances outside the control of the Corporation that have delayed activities required to hold the licenses.

Marketing and Refining

 

The Corporation’s strategy for the M&R segment is to deliver consistent operating performance and generate free cash flow. M&R earnings (losses) were $(231) million in 2010, $127 million in 2009 and $277 million in 2008. Refining operations generated losses of $445 million in 2010 and $87 million in 2009 and income of $73 million in 2008. Refining results for 2010 include an after-tax impairment charge of $289 million ($300 million pre-tax) to reduce the carrying value of the Corporation’s investment in HOVENSA L.L.C. to the estimated fair value. The refining results in 2010 and 2009 also reflect weak refining margins and lower volumes. Marketing earnings were $215 million in 2010, $168 million in 2009 and $240 million in 2008.

 

Liquidity and Capital and Exploratory Expenditures

 

Net cash provided by operating activities was $4,530 million in 2010, $3,046 million in 2009 and $4,688 million in 2008, principally reflecting fluctuations in earnings. At December 31, 2010, cash and cash equivalents totaled $1,608 million compared with $1,362 million at December 31, 2009. Total debt was $5,583 million at December 31, 2010 compared with $4,467 million at December 31, 2009. In August 2010, the Corporation issued $1,250 million of 30 year fixed-rate notes with a coupon of 5.6% that are scheduled to mature in 2041. The proceeds were used for the acquisition of 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 notes that were scheduled to mature in 2011. The Corporation’s debt to capitalization ratio at December 31, 2010 was 24.9% compared with 24.8% at the end of 2009.

 

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

 

 

 

The Corporation anticipates investing $5.6 billion in capital and exploratory expenditures in 2011, substantially all of which relates to E&P operations.

 

Consolidated Results of Operations

 

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

 

 

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 28 through 31.

 

 

 

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

 

Comparison of Results

 

Exploration and Production

 

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

 

 

 

 

After considering the E&P items in the table on page 28, the remaining changes in E&P earnings are primarily attributable to changes in selling prices, production and sales volumes, operating costs, exploration expenses, foreign exchange, and income taxes, as discussed below.

 

Selling prices:  Higher average selling prices increased E&P revenues by approximately $1,775 million in 2010 compared with 2009. Lower average selling prices reduced E&P revenues by approximately $4,000 million in 2009 compared with 2008.

The Corporation’s average selling prices were as follows: