HESS CORP - Annual Report: 2014 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 2014

or

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 ¨

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. ¨

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 $26,590,000,000 computed using the outstanding common shares and closing market price on June 30, 2014, the last business day of the Registrant’s most recently completed second fiscal quarter.

At December 31, 2014, there were 285,834,964 shares of Common Stock outstanding.

Part III is incorporated by reference from the Proxy Statement for the 2015 annual meeting of stockholders.

 HESS CORPORATION

Form 10-K

TABLE OF CONTENTS

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PART I

Hess Corporation (the Registrant) is a Delaware corporation, incorporated in 1920.  The Registrant with its subsidiaries (collectively referred to as the Corporation or Hess) is a global Exploration and Production (E&P) company that develops, produces, purchases, transports and sells crude oil, natural gas liquids, and natural gas with its production operations located primarily in the United States (U.S.), Denmark, Equatorial Guinea, the Joint Development Area of Malaysia/Thailand (JDA), Malaysia, and Norway.

In the first quarter of 2013, the Corporation announced several initiatives to continue its transformation into a more focused pure play E&P company. These initiatives represented the culmination of a multi-year strategic transformation designed to deliver long-term, cash generative growth and increase returns to stockholders by focusing on lower risk, higher growth unconventional assets, exploiting existing discoveries by leveraging offshore drilling and project development capabilities, and executing a smaller, more targeted exploratory program.

As part of its transformation, the Corporation sold over the reporting period of 2012 through 2014 mature or lower margin E&P assets in Azerbaijan, Indonesia, Norway, Russia, Thailand, the United Kingdom (UK) North Sea, and certain interests onshore in the U.S.  In addition, the transformation plan included fully exiting the Corporation’s Marketing and Refining (M&R) business, including its terminal, retail, energy marketing and energy trading operations, as well as the permanent shutdown of refining operations at its Port Reading facility.  HOVENSA L.L.C. (HOVENSA), a 50/50 joint venture between the Corporation’s subsidiary, Hess Oil Virgin Islands Corp. (HOVIC), and a subsidiary of Petroleos de Venezuela S.A. (PDVSA), had previously shut down its U.S. Virgin Islands refinery in January 2012 and continued operating solely as an oil storage terminal through the first quarter of 2015.  See Item 3. Legal Proceedings.  As of December 31, 2014, all downstream businesses were sold or shut down except for the energy trading joint venture, HETCO, which was sold in February 2015, and HOVENSA, which will be shut down in the first quarter of 2015.

See also the Overview in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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Exploration and Production

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

On a barrel of oil equivalent basis, 47% of the Corporation’s worldwide proved reserves were undeveloped at December 31, 2014 compared with 45% at December 31, 2013.  Proved reserves held under production sharing contracts at 2014 totaled 5% of crude oil and natural gas liquids reserves and 49% of natural gas reserves, compared with 7% of crude oil and natural gas liquids reserves and 46% of natural gas reserves at December 31, 2013.  Asset sales reduced proved reserves by 77 million boe in 2014, 140 million boe in 2013, and 83 million boe in 2012.

See the Supplementary Oil and Gas Data on pages 87 through 95 in the accompanying financial statements for additional information on the Corporation’s oil and gas reserves, including a discussion of the implications that potential sustained lower crude oil prices may have on proved reserves at December 31, 2015.

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

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

United States

At December 31, 2014, 51% of the Corporation’s total proved reserves were located in the U.S.  During 2014, 61% of the Corporation’s crude oil and natural gas liquids production and 32% of its natural gas production were from U.S. operations.  The Corporation’s production in the U.S. was from offshore properties in the Gulf of Mexico and onshore properties principally in the Bakken oil shale play in the Williston Basin of North Dakota, the Permian Basin of Texas, and the Utica Basin of Ohio.

Onshore:  The Corporation held approximately 613,000 net acres in the Bakken at December 31, 2014.  During 2014, the Corporation operated an average of 17 rigs, drilled 261 wells, completed 230 wells, and brought on production 238 wells, bringing the total operated production wells to 982.  In addition, the Corporation announced in 2014 it plans to develop future 1280-acre drilling space units (DSUs) primarily using a 7/6 spacing design whereby seven wells will be drilled into the Middle Bakken reservoir and six wells will be drilled into the Three Forks reservoir per DSU.  In 2015, the Corporation plans to operate an average of 9.5 rigs to drill 170 wells and bring 210 wells on production while reducing capital expenditures to $1.8 billion in 2015 from $2.2 billion in 2014. Bakken production is forecast to average between 95,000 boepd and 105,000 boepd in 2015.

In North Dakota, the Corporation owns and operates the Tioga Gas Plant.  In the first quarter of 2014, the Corporation completed an expansion of the plant that increased total processing capacity to approximately 250,000 mcf per day and 60,000 barrels per day of full NGL fractionation capabilities.  The Corporation’s Tioga Rail Terminal has loading capacity of approximately 140,000 barrels per day of crude oil and approximately 30,000 barrels per day of natural gas liquids with on-site crude oil storage of 287,000 barrels.  The Corporation also owns nine crude oil unit trains, each consisting of 104 crude oil rail cars, all of which were constructed to American Association of Railroads Petition 1577 (CPC-1232) safety standards.  Other infrastructure includes the Ramberg Truck Facility, that is capable of delivering up to an aggregate of 130,000 barrels

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per day of crude oil into an interconnecting pipeline for transportation to the Tioga Rail Terminal and to multiple third-party pipelines and storage facilities.

In 2014, the Corporation formed Hess Midstream Partners LP to own, operate, develop and acquire a diverse set of midstream assets to provide fee-based services to both Hess and third party crude oil and natural gas producers. Hess Midstream Partners LP filed a registration statement on Form S-1 in September 2014 and expects to complete an initial public offering of its securities in 2015. The assets to be held by Hess Midstream Partners LP at the time of its initial public offering are expected to include a 30% economic interest in Hess TGP Operations LP (owner of the Tioga Gas Plant), a 50% economic interest in Hess North Dakota Export Logistics Operations LP (owner of the Tioga rail terminal, Ramberg truck facility and crude oil rail cars), and a 100% interest in Hess Mentor Storage Holdings LLC (owner of a 328,000 barrel propane storage cavern with a rail and truck transloading facility).  

The Corporation also owned a 50% undivided working interest in approximately 45,000 net acres in the wet gas area of the Utica Basin of Ohio.  During 2014, a total of 38 wells were drilled, 36 wells were completed and 39 wells were brought on production as the Corporation transitioned from appraisal to early development activities. In 2015, the Corporation and its joint venture partner plan to execute a two rig drilling program that will allow for 20 to 25 wells to be drilled and for 25 to 30 wells to be brought online.  Net production is forecast to be in the range of 15,000 boepd to 20,000 boepd in 2015.  During 2014, the Corporation sold approximately 77,000 net acres of its 100% owned acreage in the dry gas area of the Utica shale play for cash proceeds of approximately $1,075 million.

In the Permian Basin, the Corporation operates and holds a 34% interest in the Seminole‑San Andres Unit.  In 2013, the Corporation sold its interests in the Eagle Ford shale play in Texas.

Offshore:  The Corporation’s production offshore in the Gulf of Mexico was principally from the Shenzi (Hess 28%), Llano (Hess 50%), Conger (Hess 38%), Baldpate (Hess 50%), Tubular Bells (Hess 57%), Hack Wilson (Hess 25%) and Penn State (Hess 50%) fields.

At the Hess operated Tubular Bells Field, the Corporation achieved first production in November 2014 following completion of construction, installation and commissioning of offshore production facilities and subsea equipment.  Three wells are currently producing with a fourth production well expected to be completed in 2015.

At the BHP Billiton Petroleum operated Shenzi Field, development drilling continued during 2014 with the completion of one production well.  A continuous drilling program is planned through 2016.

The Corporation is operator and holds a 25% interest in the Stampede offshore development project on Green Canyon Blocks 468, 511 and 512 in the Gulf of Mexico.  In 2014, the co-owners of the project sanctioned the field development and committed to two deepwater drilling rigs that are expected to commence drilling operations in the fourth quarter of 2015 and the first quarter of 2016.  Construction of production facilities and subsea equipment is underway with first production from the field targeted for 2018.

The Corporation holds a 25% interest in the Sicily prospect in the deepwater Gulf of Mexico.  The operator, Chevron, has commenced drilling of an exploration well with the objective of reaching target depth in the third quarter of 2015.

At December 31, 2014, the Corporation had interests in 177 deepwater blocks in the Gulf of Mexico, of which 148 were exploration blocks comprising approximately 550,000 net undeveloped acres, with an additional 66,000 net acres held for production and development operations.  During 2014, the Corporation’s interests in 45 leases, comprising approximately 175,000 net undeveloped acres, either expired or were relinquished.  In the next three years, an additional 81 exploration leases, comprising approximately 280,000 net undeveloped acres, are due to expire.

Europe

At December 31, 2014, 23% of the Corporation’s total proved reserves were located in Europe (Norway 20% and Denmark 3%).  During 2014, 16% of the Corporation’s crude oil and natural gas liquids production and 7% of its natural gas production were from European operations.  In 2013, the Corporation completed the sale of its Russian subsidiary, Samara‑Nafta, and sold its interests in the Beryl fields, completing its exit from producing operations in the UK North Sea. In 2012, the Corporation sold its interests in the Bittern and Schiehallion fields in the UK North Sea.

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Norway:  The Corporation’s Norwegian production was from its non-operated interests in the Valhall (Hess 64%) and Hod fields (Hess 63%).

In the first quarter of 2013, BP, the operator of the Valhall Field completed the installation of a new production, utilities and accommodation platform that extends the field life by approximately 40 years.  A multi-year drilling program is continuing and net production is forecast to be in the range of 30,000 boepd to 35,000 boepd in 2015. In addition, the operator is executing a multi-year well abandonment program.

Denmark:  Production comes from the Corporation's operated interest in the South Arne Field (Hess 62%), offshore Denmark.  Development drilling commenced in 2013 and is planned to continue through 2015.  During 2013, the Corporation completed its phase three development program in which two new wellhead platforms were successfully installed in the field.

Africa

At December 31, 2014, 15% of the Corporation’s total proved reserves were located in Africa (Equatorial Guinea 3.5%, Libya 11% and Algeria 0.5%).  During 2014, 22% of the Corporation’s crude oil and natural gas liquids production were from its African operations.

Equatorial Guinea:  The Corporation is operator and owns an interest in Block G (Hess 85% paying interest) which contains the Ceiba Field and the Okume Complex.  The national oil company of Equatorial Guinea holds a 5% carried interest in Block G.  At the Okume Complex, an infill drilling campaign commenced in the fourth quarter of 2013 based on 4D seismic and will continue into the first half of 2015.

Libya:  The Corporation, in conjunction with its Oasis Group partners, has production operations in the Waha concessions in Libya (Hess 8%) which contain the Defa, Faregh, Gialo, North Gialo, Belhedan and other fields.  Due to the civil unrest in Libya, production was shut‑in beginning in the third quarter of 2013 and restarted, on a significantly reduced rate, in the third quarter of 2014.  Net production at the Waha fields averaged 4,000 boepd in 2014, 15,000 boepd during 2013 and 21,000 boepd in 2012.  In December 2014 the Libyan National Oil Company declared force majeure with respect to the Waha fields and production is currently shut-in.  In addition, the Corporation expensed two previously capitalized exploration wells on offshore exploration Area 54 in the Mediterranean Sea in the fourth quarter of 2013 due to the ongoing civil and political unrest.  The Libyan operations have assets with a book value of $365 million at December 31, 2014.

Algeria:  The Corporation has a 49% interest in a venture with the Algerian national oil company that redeveloped three oil fields.  In 2013, the Corporation sold its interest in the development project, Bir El Msana (Hess 45%).

Ghana:  The Corporation holds a 44% paying interest and is operator of the Deepwater Tano Cape Three Points license while the Ghana National Petroleum Corporation holds an 11% paying interest and a 10% carried interest in the block.  These ownership percentages are based on terms of a farmout agreement with a third party that is subject to approval by the Ghanaian government.  The Corporation has drilled seven successful exploration wells on the block since 2011.  In June 2013, the Corporation submitted appraisal plans for each of the seven discoveries, which comprise both oil and natural gas condensates, to the Ghanaian government for approval.  Approval has been received on four appraisal plans and discussions continue with the Ghanaian government to receive approval on the remaining three appraisal plans.  In 2014, the Corporation drilled three successful appraisal wells.  In 2015 the Corporation and its partners will continue to analyze data from both appraisal drilling and 3D seismic with an expected project sanction decision in 2016.  See Capitalized Exploratory Well Costs in Note 6 – Property, Plant and Equipment in Notes to Consolidated Financial Statements.

Asia and Other

At December 31, 2014, 11% of the Corporation’s total proved reserves were located in the Asia region (JDA 7% and Malaysia 4%).  During 2014, 1% of the Corporation’s crude oil and natural gas liquids production and 61% of its natural gas production were from its Asian and Other operations.  The Corporation completed the sale of its interests in Thailand in April 2014.  In addition, the Corporation sold its Pangkah asset and its interest in the Natuna A Field, both offshore Indonesia, in January 2014 and December 2013, respectively.  In the first quarter of 2013, the Corporation sold its interests in Azerbaijan in the Caspian Sea.

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 2014, the operator continued development drilling and successfully installed a new

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wellhead platform.   Further development drilling is planned for 2015 and the completion of a booster compression project is planned for early 2016.  Net production in 2015 is expected to be approximately 250,000 million cubic feet per day.

Malaysia:  The Corporation’s production in Malaysia comes from its interest in Block PM301 (Hess 50%), which is adjacent to and is unitized with Block A‑18 of the JDA and its 50% interest in Blocks PM302, PM325 and PM326B located in the North Malay Basin (NMB), offshore Peninsular Malaysia, where the Corporation is operator of a multi‑phase natural gas development project.  NMB achieved first production in October 2013 from an Early Production System. The Corporation expects net production to average approximately 40 million cubic feet per day through 2016 until full field development is completed.  Net production is expected to increase to approximately 165 million cubic feet per day in 2017.

Australia:  The Corporation holds an 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) (Hess 100%).  The Corporation has drilled 13 natural gas discoveries.  Development planning and commercial activities continued in 2014, which included the execution of a non-binding letter of intent with a potential liquefaction partner.  Successful negotiation of a binding agreement with the third party liquefaction partner is necessary before the Corporation can execute a gas sales agreement and sanction development of the project.  See Capitalized Exploratory Well Costs in Note 6 – Property, Plant and Equipment in Notes to Consolidated Financial Statements.

Kurdistan Region of Iraq:  The Corporation is operator and holds an 80% paying interest (64% working interest) in the Dinarta exploration block.  Drilling activities have been suspended on the Shireen exploration well in the Dinarta Block and the Corporation is currently assessing its completion options.

China:  In July 2013, the Corporation signed a Production Sharing Agreement (PSA) with China National Petroleum Corporation to evaluate unconventional oil and gas resource opportunities covering approximately 200,000 gross acres in the Santanghu Basin.  The exploration phase commenced in August 2013 and two wells were drilled and expensed.  In December, 2014 the Corporation provided formal notice of its intent to end its participation in the PSA.

Guyana:  The Corporation holds a 30% participating interest in the offshore Stabroek license.  The Corporation anticipates the operator, Esso Exploration and Production Guyana Limited, to commence drilling of the Liza-1 well in March 2015.

Canada:  The Corporation received regulatory approval to hold a 40% participating interest in four exploration licenses offshore Nova Scotia.  The Corporation expects the operator, BP, to commence exploration drilling in 2017.

Sales Commitments

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 96 billion cubic feet per year based on current entitlements under a sales contract with the national oil companies of Malaysia and Thailand expiring in 2027.  At the North Malay Basin development project, the Corporation has a commitment to deliver a minimum of 24 billion cubic feet of natural gas per year from full field development start-up, which is expected in 2017, through 2033.  The estimated total volume of production subject to sales commitments is approximately 1.7 trillion cubic feet of natural gas.

The Corporation has NGL delivery commitments in the Bakken and Permian Basin of Texas through 2023 of approximately 9 million barrels per year, or approximately 99 million barrels over the life of the contracts.

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 and projected third party supply.

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Average selling prices and average production costs

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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.

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Marketing and Refining- Discontinued Operations

All downstream businesses were sold or shutdown as of December 31, 2014, except for the energy trading joint venture, HETCO, which was sold in February 2015, and HOVENSA, which will be shut down in the first quarter of 2015.

In the third quarter of 2014, the Corporation sold its retail marketing business consisting of approximately 1,350 retail gasoline stations, most of which had convenience stores.  In addition, the Corporation sold in 2014 two joint venture investments in natural gas fueled electric generating projects in Newark and Bayonne, New Jersey.

In the fourth quarter of 2013, the Corporation sold its energy marketing and terminal network businesses which marketed refined petroleum products, natural gas and electricity on the East Coast of the U.S. primarily to wholesale distributors, industrial and commercial users, and public utilities.  In the first quarter of 2013, the Corporation permanently shut down refining operations at its Port Reading, New Jersey facility, thus completing its exit from all refining operations.

Hess Oil Virgin Islands Corp. (HOVIC), a subsidiary of the Corporation, has a 50% interest in HOVENSA, a joint venture with a subsidiary of PDVSA, which owns a refinery in St. Croix, U.S. Virgin Islands.  In January 2012, HOVENSA shut down its refinery and continued operating solely as an oil storage terminal through the first quarter of 2015.  HOVENSA and the Government of the Virgin Islands agreed to a plan to pursue a sale of HOVENSA and the sales process commenced in the fourth quarter of 2013.  In the fourth quarter of 2014, the Government of the Virgin Islands did not approve a proposed operating agreement required to complete a proposed sale of HOVENSA.  See Item 3. Legal Proceedings.

Competition and Market Conditions

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

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Other Items

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 (CGA), Marine Spill Response Corporation (MSRC), Marine Well Containment Company (MWCC), Wild Well Control (WWC), Subsea Well Intervention Service (SWIS), National Response Corporation (NRC) and Oil Spill Response Limited (OSRL).  CGA and MSRC are  domestic spill response organizations and MWCC provides the equipment and personnel to contain underwater well control incidents in the Gulf of Mexico.  WWC provides firefighting, well control and engineering services globally.  NRC and OSRL 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 600,000 feet of boom, and significant quantities of dispersants and other ancillary equipment, including aircraft.  In addition to external well control and oil spill response support, the Corporation has contracts with wildlife, environmental, meteorology, incident management, medical and security resources.  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 Committees of CGA and MSRC, as well as the Board of Directors of OSRL.

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 Atlantic Named Windstorm coverage 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 $300 million of coverage is provided through an industry mutual insurance group.  Above this $300 million threshold, insurance is carried which ranges in value up to $2.53 billion in total, depending on the asset coverage level, as described above.  Additionally, the Corporation carries insurance that provides third party coverage for general liability, and sudden and accidental pollution, up to $1.08 billion, which coverage under a standard joint operating arrangement would be reduced to the Corporation’s participating interest.

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The Corporation’s insurance policies renew at various dates each year.  Future insurance coverage 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 (and, often, those of its contractors/subcontractors) regardless of fault.  Variations may 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 cause, 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 damage to reservoirs, blowouts, cratering and loss of hole, regardless of cause, although exceptions for losses attributable to gross negligence and/or willful misconduct do exist.  Lastly, some offshore services contracts include overall limitations of the Contractor’s liability equal to the value of the contract or a fixed amount.

Under a standard joint operating agreement (JOA), each party is liable for all claims arising under the JOA, to the extent of its participating interest (operator or non-operator).  Variations include indemnity exclusions when the claim is based upon the gross negligence and/or willful misconduct of the operator, in which case the operator is solely liable.  The parties to the JOA may continue to be jointly and severably liable for claims made by third parties in some jurisdictions.  Further, under some production sharing contracts between a governmental entity and commercial parties, liability of the commercial parties to the government 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 but increasingly stringent environmental regulations 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.  The Corporation spent approximately $12 million in 2014 for environmental remediation, principally relating to the downstream businesses.  The level of other expenditures to comply with federal, state, local and foreign country environmental regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of the Corporation’s capital expenditures and operating expenses.  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 was approximately 3,045 at December 31, 2014 and approximately 12,225 at December 31, 2013, of which approximately 8,700 related to the retail business which was sold in 2014.

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.

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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 liquids and natural gas, which can be very volatile.  Our estimated proved reserves, revenue, operating cash flows, operating margins, and future earnings are highly dependent on the prices of crude oil, natural gas liquids and natural gas, which are volatile and influenced by numerous factors beyond our control.  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.  In the fourth quarter of 2014, prices for Brent crude oil and West Texas Intermediate crude oil declined by approximately 40% to end the year at $57 per barrel and $53 per barrel, respectively. If crude oil prices remain at these levels for the remainder of 2015, there will be a significant decrease in 2015 revenues, and earnings from 2014 levels. We cannot predict how long these lower price levels will continue to prevail.  The commodities trading markets as well as other supply and demand factors may also influence the selling prices of crude oil, natural gas liquids and natural gas.  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 order to manage the potential volatility of cash flows and credit requirements, the Corporation maintains 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.  In addition, we are exposed to risks related to changes in interest rates and foreign currency values, and may engage in hedging activities to mitigate related volatility.

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.  Similar risks, however, may be encountered in the production of oil and gas on properties acquired from others.  In addition to the technical risks to reserve replacement, replacing reserves and developing future production is also influenced by the price of crude oil and natural gas. Persistent lower crude oil and natural gas prices, such as those currently prevailing, may have the effect of reducing capital available for exploration and development activity and may render certain development projects uneconomic or delay their completion and may result in negative revisions to existing reserves.

There are inherent uncertainties in estimating quantities of proved reserves and discounted future net cash flows, 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. Crude oil prices declined significantly in the fourth quarter of 2014.  See Crude Oil and Natural Gas Reserves in Critical Accounting Policies and Estimates in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We do not always control decisions made under joint operating agreements and the partners under such agreements may fail to meet their obligations.  We conduct many of our exploration and production operations through joint operating agreements with other parties under which we may not control decisions, either because we do not have a controlling interest or are not operator under the agreement.  There is risk that these parties may at any time have economic,

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business, or legal interests or goals that are inconsistent with ours, and therefore decisions may be made which are not what we believe is in our best interest.  Moreover, parties to these agreements may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone.  In either case, the value of our investment may be adversely affected.

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, imposition of capital controls or blocking of funds, changes in import and export regulations, limitations on access to exploration and development opportunities, anti-bribery or anti-corruption laws, as well as other political developments may affect our operations. We transport some of our crude oil production, particularly from the Bakken shale oil play, by rail.  Recent rail accidents have raised public awareness of rail safety and resulted in heightened regulatory scrutiny.  We own our own fleet of tank cars that exceed the current federal standards for construction and safety.  We expect that in 2015, the Department of Transportation will issue new standards for tank car design which may require us to retrofit our existing tank cars.  Depending on the requirements of the regulation, changes in tank car design and limitations on the availability of shop capacity to undertake retrofits, as well as other possible regulations aimed at increasing rail safety, may lead to a significant increase in the costs of transporting crude oil and other hydrocarbons by rail and otherwise adversely affect our operations.

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 and may be subject to civil unrest, conflict, insurgency, corruption, security risks and labor unrest.  Political and civil unrest in North Africa and the Middle East has affected and 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 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.  Our operations are also subject to numerous U.S. 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 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.  Similarly, the Corporation has material legal obligations to dismantle, remove and abandon production facilities and wells that will occur many years in the future, in most cases.  These estimates may be impacted by future changes in regulations and other uncertainties.

Concerns have been raised in certain jurisdictions where we have operations concerning the safety and environmental impact of the drilling and development of shale oil and gas resources, particularly hydraulic fracturing, water usage, flaring of associated natural gas and air emissions.  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.

Climate change initiatives may result in significant operational changes and expenditures, reduced demand for our products and adversely affect our business.  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, our production is used to produce petroleum fuels, which through normal customer use may result in the emission of greenhouse gases.  Regulatory initiatives to reduce the use of these fuels may reduce our sales of crude oil and other hydrocarbons.  The imposition and enforcement of stringent greenhouse gas emissions reduction targets could severely and adversely impact the oil and gas industry and significantly reduce the value of our business.  

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.  Many competitors,

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including national oil companies, are larger and have substantially greater resources.  We are also in competition with producers of other forms of energy.  Increased competition for worldwide oil and gas assets has significantly increased the cost of acquiring oil and gas assets.  In addition, competition for drilling services, technical expertise and equipment may affect 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, blowouts, such as the third party accident at the Macondo prospect, pipeline interruptions and ruptures, severe weather, geological events, labor disputes or cyber‑attacks.  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.

Significant time delays between the estimated and actual occurrence of critical events associated with development projects may result in material negative economic consequences.  The Corporation is involved in several large development projects and the completion of those projects may be delayed beyond what was originally anticipated.  Such examples include, but are not limited to, delays in receiving necessary approvals from project members or regulatory agencies, timely access to necessary equipment, availability of necessary personnel and unfavorable weather conditions.  This may lead to delays and differences between estimated and actual timing of critical events.  These delays could impact information detailed in forward-looking statements, and may have material negative economic consequences.

Departures of key members from the Corporation’s senior management team, and/or difficulty in recruiting and retaining adequate numbers of experienced technical personnel, could negatively impact the Corporation’s ability to deliver its strategic goals.    The derivation and monitoring of successful strategies and related policies may be negatively impacted by the departure of key members of senior management.  Moreover, an inability to recruit and retain adequate numbers of experienced technical and professional personnel in the necessary locations may prohibit the Corporation from executing its strategy in full or, in part, with a commensurate impact on shareholder value.

The Corporation is dependent on oilfield service companies for items including drilling rigs, equipment, supplies and skilled labor.  An inability or significant delay in securing these services, or a high cost thereof, may result in material negative economic consequences.  The availability and cost of drilling rigs, equipment, supplies and skilled labor will fluctuate over time given the cyclical nature of the Exploration and Production industry.  As a result, the Corporation may encounter difficulties in obtaining required services or could face an increase in cost.  These consequences may impact the ability of the Corporation to run its operations and to deliver projects on time with the potential for material negative economic consequences.

Cyber‑attacks targeting computer, telecommunications systems, and infrastructure used by the oil and gas industry may materially impact our business and operations.  Computers and telecommunication systems are used to conduct our exploration, development and production activities and have become an integral part of our business.  We use these systems to analyze and store financial and operating data and to communicate within our company and with outside business partners.  Cyber‑attacks could compromise our computer and telecommunications systems and result in disruptions to our business operations or the loss of our data and proprietary information.  In addition, computers control oil and gas production, processing equipment, and distribution systems globally and are necessary to deliver our production to market.  A cyber‑attack against these operating systems, or the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or prevent delivery to markets, and make it difficult or impossible to accurately account for production and settle transactions.  As a result, a cyber-attack could have a material adverse impact on our cash flows and results of operations.  We routinely experience attempts by external parties to penetrate and attack our networks and systems.  Although such attempts to date have not resulted in any material breaches, disruptions, or loss of business critical information, our systems and procedures for protecting against such attacks and mitigating such risks may prove to be insufficient in the future and such attacks could have an adverse impact on our business and operations.

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Item 3. Legal Proceedings

The Corporation, along with many 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 U.S. 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. The majority of the cases asserted against the Corporation have been settled. In 2014, the Corporation settled and paid claims against it arising out of an action brought by the State of New Jersey for approximately $35 million.  The settlement was approved by the trial judge and the Corporation paid the settlement amount in December 2014.  In June 2014, the Commonwealth of Pennsylvania and the State of Vermont each filed independent lawsuits alleging that the Corporation and all major oil companies with operations in each respective state, have damaged the groundwater in those states by introducing thereto gasoline with MTBE.  The Pennsylvania suit has been removed to Federal court and has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. The suit filed in Vermont is proceeding there in a state court.  An action brought by the Commonwealth of Puerto Rico also remained unresolved at December 31, 2014. The Corporation has recorded reserves for its estimated liabilities for its unresolved MTBE lawsuits.

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 previously 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 Corporation and other parties recently settled a cost recovery claim by the State of New Jersey and also agreed to fund remediation of a portion of the site.  The EPA is continuing to study contamination and remedial designs for other portions of the River.  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 proposed total penalties of $210,000.  HOVENSA believes that it has good defenses against the asserted violations.

In July 2004, HOVIC 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. In 2014 HOVIC, HOVENSA and the government of the U.S. Virgin Islands entered into a settlement agreement pursuant to which HOVENSA paid $3.5 million and agreed to pay the government of the U.S. Virgin Islands an additional $40 million no later than December 31, 2014.  HOVENSA was unable to make this additional payment because the U.S.Virgin Islands legislature did not approve a proposed operating agreement required to complete a proposed sale of HOVENSA, which would have provided funds to make the settlement payment. Under the terms of the settlement agreement, the U.S. Virgin Islands government was granted a first lien on HOVENSA’s assets to secure the settlement payment, and in January 2015 the government commenced a foreclosure action to enforce this lien.  HOVENSA intends to defend this action and may take other steps in response to the action, including the sale of assets and/or the commencement of bankruptcy proceedings. The Registrant does not believe that the resolution of this matter will have a material adverse effect on its financial condition.

In February 2015, the Pension Benefit Guaranty Corporation (PBGC) issued a notice of determination to terminate the HOVENSA pension plan. HOVENSA had been in negotiations with the PBGC to make additional contributions to the plan

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with proceeds from a proposed sale of HOVENSA, which was not completed for the reasons described above. The Registrant does not believe that the resolution of this matter will have a material adverse effect on its financial condition.

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.

Item 4. Mine Safety Disclosures

None.

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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:

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:

Comparison of Five‑Year Shareholder Returns

Years Ended December 31,

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Holders

At December 31, 2014, there were 3,752 stockholders (based on the number of holders of record) who owned a total of 285,834,964 shares of common stock.

Dividends

In 2014, cash dividends on common stock totaled $1.00 per share ($0.25 per quarter).  In 2013, cash dividends declared on common stock totaled $0.70 per share ($0.10 per share for the first two quarters and $0.25 per share commencing in the third quarter of 2013). Cash dividends were $0.40 per share ($0.10 per quarter) in 2012.

  Share Repurchase Activities

Hess’s share repurchase activities for the year ended December 31, 2014, were as follows:

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Equity Compensation Plans

Following is information on the Registrant’s equity compensation plans at December 31, 2014.

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

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Item 6.  Selected Financial Data

The following is a five‑year summary of selected financial data that should be read in conjunction with the Corporation’s consolidated financial statements and the accompanying notes and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this Annual Report: