HESS CORP
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. 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 utilizes significant bank credit facilities. An inability to renew or replace such credit facilities or access other sources of funding as they mature would negatively impact our liquidity. 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.
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.
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, 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, as well as other political developments may affect our operations. As a result of the accident in April 2010 at the BP p.l.c. (BP) operated Macondo prospect in the Gulf of Mexico (in which the Corporation was not a participant) and the ensuing significant oil spill, a temporary drilling moratorium was imposed in the Gulf of Mexico. While this moratorium has since been lifted, significant new regulations have been imposed and further legislation and regulations may be proposed. The new regulatory environment has resulted in a longer permitting process and higher costs. We also 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 may result in heightened regulatory scrutiny that may lead to an increase in the costs of transporting crude oil and other hydrocarbons by rail and otherwise adversely impact 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. 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. For example, production at the Waha fields in Libya, which has a net production capacity of approximately 25,000 boepd, has been shut-in since August 2013 and was also shut-in for eight months in 2011 due to civil unrest. 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.
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. For example, a moratorium prohibiting hydraulic fracturing is currently impacting the Corporation’s exploration activities in France.
Concerns about climate change 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. 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 higher costs and lost revenues related to delays and shutdowns.
Our industry is highly competitive and many of our competitors are larger and have greater resources than we have. The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies in each of our activities, including acquiring rights to explore for crude oil and natural gas. Many competitors, 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.
Cyber-attacks targeting our computer and 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, the loss or corruption of our data and proprietary information and communications interruptions. In addition, computers control oil and gas distribution systems globally and are necessary to deliver our production to market. A cyber-attack impacting these distribution 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. Our systems and procedures for protecting against such attacks and mitigating such risks may prove to be insufficient and such attacks could have an adverse impact on our business and operations.
Item 3. Legal Proceedings
The Corporation, along with many other companies engaged in refining and marketing of gasoline, has been a party to lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline. A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the 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. In 2008, the majority of the cases against the Corporation were settled. In 2010 and 2011, additional cases were settled including an action brought in state court by the State of New Hampshire. Cases brought by the State of New Jersey and the Commonwealth of Puerto Rico remain unresolved. The Corporation has reserves recorded which it believes are adequate to cover its expected liability in these cases.
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. The CERCLA claims have been dismissed and a trial is scheduled in June 2014 on the remaining claims. HOVIC and HOVENSA are continuing to vigorously defend this matter and do not believe that this matter will result in a material liability as they believe that they have strong defenses against this complaint.
The Corporation periodically receives notices from the EPA that it is a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties are jointly and severally liable. For certain sites, the EPA’s claims or assertions of liability against the Corporation relating to these sites have not been fully developed. With respect to the remaining sites, the EPA’s claims have been settled, or a proposed settlement is under consideration, in all cases for amounts that are not material. The ultimate impact of these proceedings, and of any related proceedings by private parties, on the business or accounts of the Corporation cannot be predicted at this time due to the large number of other potentially responsible parties and the speculative nature of clean-up cost estimates, but is not expected to be material.
The Corporation is from time to time involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. The Corporation cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such proceedings is not expected to have a material adverse effect on the financial condition, results of operations or cash flows of the Corporation.
Item 4. Mine Safety Disclosures
None.
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:
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Standard & Poor’s (S&P) 500 Stock Index, which includes the Corporation,
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Proxy Peer Group comprising 16 oil and gas peer companies, including the Corporation (as disclosed in the Corporation’s 2013 Proxy Statement).
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
Holders
At December 31, 2013, there were 3,961 stockholders (based on the number of holders of record) who owned a total of 325,314,177 shares of common stock.
Dividends
In 2013, cash dividends 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) for both 2012 and 2011.
Share Repurchase Activities
Hess’s share repurchase activities for the year ended December 31, 2013, were as follows:
(a) Repurchased in open-market transactions. The average price paid per share was inclusive of transaction fees.
(b) In March 2013, the Corporation announced a board authorized plan to repurchase up to $4 billion of outstanding common shares.
Equity Compensation Plans
Following is information on the Registrant’s equity compensation plans at December 31, 2013:
(a) These securities may be awarded as stock options, restricted stock, performance share units or other awards permitted under the Registrant’s equity compensation plan.
(b) The Corporation has a Stock Award Program pursuant to which each non-employee director annually receives approximately $175,000 in value of the Corporation’s common stock. These awards are made from shares purchased by the Corporation in the open market.
See Note 13, Share-based Compensation in the notes to the Consolidated Financial Statements for further discussion of the Corporation’s equity compensation plans.
Item 6. Selected Financial Data
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
Overview
Hess Corporation (the Corporation or Hess) is a global Exploration and Production (E&P) company that develops, produces, purchases, transports and sells crude oil and natural gas. Prior to 2013, the Corporation also operated a Marketing and Refining (M&R) segment, which it began to divest during the year. The M&R businesses manufacture refined petroleum products and purchase, market, store and trade refined products, natural gas and electricity, as well as operate retail gas stations, most of which have convenience stores.
In the first quarter of 2013, the Corporation announced several initiatives to continue its transformation into a more focused pure play E&P company that is expected to deliver compound average production growth of 5% to 8% through 2017, from its 2012 pro forma production of 289,000 barrels of oil equivalent per day (boepd). The transformation plan included fully exiting the Corporation’s M&R businesses, including its terminal, retail, energy marketing and energy trading operations, as well as the permanent shutdown of refining operations at its Port Reading facility, thus completing its exit from all refining operations. 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 United States (U.S.) Virgin Islands refinery in January 2012 and continued operating solely as an oil storage terminal. HOVIC and its partner have also commenced a sales process for HOVENSA. The transformation plan also committed to the sale of mature E&P assets in Indonesia and Thailand and the pursuit of monetizing Bakken midstream assets by 2015.
As part of its transformation during 2012 and 2013, the Corporation sold mature or lower margin assets in Azerbaijan, Indonesia, Norway, Russia, the United Kingdom (UK) North Sea, and certain interests onshore in the U.S. In the fourth quarter of 2013, the Corporation sold its energy marketing business and its terminal network. In 2014, the Corporation plans to divest its remaining downstream businesses, including its retail marketing business and energy trading joint venture, plus its E&P assets in Thailand. The Corporation has also reached an agreement to sell dry gas acreage in the Utica shale play in the U.S.
Other actions announced by the Corporation in March 2013 included repaying debt, establishing a cash cushion and returning capital to shareholders. By year-end 2013, approximately $2.4 billion of short-term debt had been repaid. In addition, commencing in the third quarter of 2013, the Corporation increased its quarterly dividend 150% to $0.25 per common share and commenced share repurchases under its authorized $4 billion share repurchase program. Through December 31, 2013, Hess had purchased approximately 19.3 million common shares at a cost of approximately $1.54 billion.
Net income was $5,052 million in 2013 compared with $2,025 million in 2012 and $1,703 million in 2011. Diluted earnings per share were $14.82 in 2013 compared with $5.95 in 2012 and $5.01 in 2011. Excluding items affecting comparability, net income was $1,892 million in 2013, $1,998 million in 2012, and $1,984 million in 2011. See the table of items affecting comparability of earnings between periods on page 24.
Exploration and Production
The Corporation’s total proved reserves were 1,437 million barrels of oil equivalent (boe) at December 31, 2013 compared with 1,553 million boe at December 31, 2012 and 1,573 million boe at December 31, 2011. Proved reserves related to assets sold in 2013 totaled 139 million boe. Pro forma year-end reserves, which exclude assets in Indonesia and Thailand classified as held for sale at December 31, 2013, were 1,362 million boe.
E&P earnings were $4,303 million in 2013, $2,212 million in 2012 and $2,675 million in 2011. Excluding items affecting comparability of earnings between periods on page 28, E&P net income was $2,192 million, $2,256 million and $2,431 million for 2013, 2012 and 2011, respectively. Average realized crude oil selling prices including the impact of hedging were $98.48 per barrel in 2013, $86.94 in 2012 and $89.99 in 2011. Average realized natural gas selling prices were $6.64 per mcf in 2013, $6.16 in 2012 and $5.96 in 2011. Production averaged 336,000 boepd in 2013, 406,000 boepd in 2012 and 370,000 boepd in 2011.
Excluding production from assets sold and classified as held for sale, pro forma production was 285,000 boepd in 2013 and 289,000 boepd in 2012. The Corporation expects compound average annual production growth of 5% to 8% through 2017, from 2012 pro forma production. The Corporation currently expects total worldwide production to average between 305,000 boepd and 315,000 boepd in 2014, excluding asset sales and any contribution from Libya, which has a net
production capacity of approximately 25,000 boepd and is shut-in due to civil unrest in the country. Pro forma production excluding Libya was 270,000 boepd in 2013 and 268,000 boepd in 2012.
The following is an update of significant E&P activities during 2013:
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In North Dakota, net production from the Bakken oil shale play averaged 67,000 boepd during 2013, an increase of 20% from 56,000 boepd in 2012 despite the transition to pad drilling in the first half of the year and the required shut-ins late in the fourth quarter of 2013 for the expansion of the Tioga Gas Plant which is expected to be operational in the first quarter of 2014. Production is expected to average between 80,000 boepd and 90,000 boepd in 2014, an increase of 19% to 34% from 2013. The Corporation also increased its peak net production guidance for the Bakken to 150,000 boepd in 2018 from prior guidance of 120,000 boepd in 2016, based upon performance to date and current development spacing based on five Middle Bakken wells and four Three Forks wells per 1,280 acre Drilling Spacing Unit (DSU). During 2014, the Corporation plans to pilot test tighter well spacing to determine whether there is additional upside in the estimates for future production and resources. During the year, 168 wells were brought on production bringing the total operated production wells to 722 . In 2014, the Corporation plans to increase the rig count in the Bakken to 17 from 14 but expects to maintain capital spending at approximately $2.2 billion, which is consistent with 2013 levels.
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At the Valhall Field in Norway (Hess 64%), net production averaged 23,000 boepd during 2013, compared with 13,000 boepd during 2012. The Field was shut-in during the second half of 2012 and January 2013 to complete a multiyear redevelopment project. Full year 2014 net production for Valhall is expected to be in the range of 30,000 boepd to 35,000 boepd.
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In the North Malay Basin, the project achieved first production from the Early Production System in October 2013 and net production averaged approximately 30 million cubic feet per day in the fourth quarter. The Corporation expects net production to average approximately 40 million cubic feet per day through 2016 until full field development is completed in late 2016. Net production is expected to increase to approximately 165 million cubic feet per day in 2017.
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In December 2013, the Corporation commenced production from its phase three development program at the South Arne Field (Hess 62%) offshore Denmark, following the installation of two new wellhead platforms and modifications to existing production facilities. Development drilling will continue in 2014.
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At Block A-18 of the Joint Development Area of Malaysia/Thailand (JDA), the Corporation successfully installed two new wellhead platforms and progressed a major booster compression project that is expected to be completed in 2015.
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In the Utica shale, 29 wells were drilled, 24 wells were completed and 17 wells were tested across both the Corporation’s 100% owned and joint venture acreage. Production test rates in the wet gas area averaged over 2,200 boepd with 47% liquids.
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In Libya, production from the Waha fields was shut-in late August of 2013 and remains shut-in due to civil unrest in the country. For the full year 2013, Libya production averaged 15,000 boepd. In addition, the Corporation wrote-off in the fourth quarter two previously capitalized exploration wells in offshore Area 54 which resulted in a pre-tax charge of $260 million ($163 million after income taxes).
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During the year, the Corporation completed drilling its second and third production wells at the Tubular Bells Field, offshore U.S., and commenced a batch completion program during the fourth quarter of 2013 for the three wells drilled to date. Facilities construction is ongoing with offshore installation expected to commence in the first quarter and first oil in the third quarter of 2014 at a net rate of 25,000 boepd.
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The Corporation completed its exploration drilling phase on the Deepwater Tano Cape Three Points Block, offshore Ghana that resulted in a total of seven successful exploration wells. The Corporation submitted appraisal plans to the Ghanaian government and four appraisal areas have been approved to date. A three well appraisal drilling program has been scheduled in the second half of 2014.
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In the third quarter, the Corporation spud its first exploration well on the Shakrok block in the Kurdistan Region of Iraq (Hess 80%) and plans to begin drilling an exploration well on the Dinarta block in the first half of 2014.
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During 2013, the E&P segment sold its assets in Azerbaijan and Russia as well as its interests in the Natuna A Field, offshore Indonesia, the Beryl fields in the UK North Sea and certain interests onshore in the U.S., for total proceeds of approximately $4.5 billion. Asset sales reduced production by approximately 60,000 boepd in 2013 compared to 2012. In January 2014, the Corporation announced it had reached agreement to sell approximately 74,000 acres of its 100% interest in the Utica Shale for $924 million. Approximately two-thirds of these proceeds are expected at the end of the first quarter of 2014, with the balance to be received in the third quarter of 2014.
Downstream Businesses
The downstream businesses reported income of $1,189 million in 2013 and $231 million in 2012 and a loss of $584 million in 2011. Excluding items affecting comparability of earnings between periods on page 31, the downstream businesses generated income of $116 million in 2013 and $160 million in 2012 and a loss of $59 million in 2011. The downstream businesses comprise the Corporation’s retail, energy marketing, terminal, energy trading and refining operations, together with its interests in two power plant joint ventures. By year-end all of these businesses were either divested by the Corporation or the divestiture processes remained on-going.
Liquidity and Capital and Exploratory Expenditures
Net cash provided by operating activities was $4,870 million in 2013, $5,660 million in 2012 and $4,984 million in 2011. At December 31, 2013, cash and cash equivalents totaled $1,814 million, up from $642 million at December 31, 2012. Total debt was $5,798 million at December 31, 2013 and $8,111 million at December 31, 2012. The Corporation’s debt to capitalization ratio at December 31, 2013 was 19.0% compared with 27.7% at the end of 2012.
Capital and exploratory expenditures were as follows:
* Includes capital expenditures related to discontinued operations of $33 million, $52 million and $65 million in 2013, 2012 and 2011, respectively.
The Corporation anticipates investing approximately $5.8 billion in E&P capital and exploratory expenditures in 2014 and approximately $350 million for retail marketing, primarily for the acquisition of its partner’s share of the WilcoHess joint venture which closed in January 2014.
Consolidated Results of Operations
The after-tax income (loss) by major operating activity is 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 following discussion and elsewhere in this report, the financial effects of certain transactions are disclosed on an after-tax basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment earnings. Management believes that after-tax amounts are a preferable method of explaining variances in earnings, since they show the entire effect of a transaction rather than only the pre-tax amount. After-tax amounts are determined by applying the income tax rate in each tax jurisdiction to pre-tax amounts.
Comparison of Results
Exploration and Production
Following is a summarized income statement of the Corporation’s E&P operations:
Excluding the E&P items affecting comparability of earnings between periods in the table on page 28, the changes in E&P earnings are primarily attributable to changes in selling prices, production and sales volumes, cost of products sold, cash operating costs, depreciation, depletion and amortization, exploration expenses and income taxes, as discussed below.
Selling Prices: Average crude oil realized selling prices were 13% higher in 2013 compared to 2012 due to a combination of hedging losses realized in 2012, the second quarter 2013 sale of the Corporation’s subsidiary in Russia which had significantly lower crude oil prices, and slightly higher average West Texas Intermediary (WTI) benchmark prices in 2013. Average crude oil realized selling prices were 3% lower in 2012 compared with 2011, primarily due to lower average WTI benchmark prices.
The Corporation’s average selling prices were as follows:
Crude oil price hedging contracts increased E&P Sales and other operating revenues by $39 million ($25 million after income taxes) in 2013, and reduced E&P Sales and other operating revenues by $688 million ($431 million after income taxes) in 2012 and $517 million ($327 million after income taxes) in 2011. During 2013, the Corporation had Brent crude oil fixed-price swap contracts to hedge 90,000 barrels of oil per day (bopd) of crude oil sales volumes at an average price of $109.70 per barrel. In 2012, the Corporation had Brent crude oil fixed-price swap contracts to hedge 120,000 bopd of crude oil sales volumes for the full year at an average price of $107.70 per barrel. In 2011 and 2012, the Corporation also realized hedge losses from previously closed Brent crude oil hedges that covered 24,000 bopd during the year. The Corporation has entered into Brent crude oil fixed-price swap contracts to hedge 25,000 bopd for calendar year 2014 at an average price of $109.12 per barrel.
Production Volumes: The Corporation’s crude oil and natural gas production was 336,000 boepd in 2013, 406,000 boepd in 2012 and 370,000 boepd in 2011. Approximately 72% in 2013, 75% in 2012 and 72% in 2011 of the Corporation’s
production was from crude oil and natural gas liquids. The Corporation currently expects total worldwide production to average between 305,000 boepd and 315,000 boepd in 2014, excluding asset sales and any contribution from Libya, which has a net production capacity of approximately 25,000 boepd and is shut-in due to civil unrest in the country.
The Corporation’s net daily worldwide production was as follows:
* Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. In addition, natural gas liquids do not sell at prices equivalent to crude oil. See the average selling prices on page 25.
United States: Crude oil, natural gas liquids and natural gas production was comparable in 2013 and 2012, as higher production from the Bakken oil shale play was partly offset by natural decline and maintenance in the other U.S. assets. Crude oil, natural gas liquids and natural gas production was higher in 2012 compared with 2011, primarily due to new wells in the Bakken oil shale play. In the second quarter of 2012, production restarted following the successful workover of a well in the Llano Field, which had been shut-in for mechanical reasons since the first quarter of 2011.
Europe: Crude oil and natural gas production was lower in 2013 compared to 2012, primarily due to asset sales. The Bittern and Schiehallion fields in the UK North Sea, which were sold in the second half of 2012, were producing at an aggregate net rate of approximately 12,000 boepd at the time of sale. The Beryl fields, also in the UK North Sea, which were producing at an aggregate net rate of approximately 10,000 boepd at the time of sale, were sold in the first quarter of 2013, and the Corporation’s Russian subsidiary, which was producing approximately 50,000 boepd at the time of sale, was sold in April 2013. Crude oil production in 2012 was lower than 2011, primarily due to the downtime at the Valhall Field in
Norway, during the second half of 2012. Natural gas production was lower in 2012 compared with 2011, primarily due to the sale of the Snohvit Field, offshore Norway, in January 2012, downtime at the Valhall Field and natural decline at the Beryl fields in the UK North Sea.
Africa: Crude oil production in Africa was lower in 2013 compared to 2012, primarily due to the shutdown of the Es Sider terminal in Libya in the third quarter of 2013, following civil unrest in the country. In addition, offshore Equatorial Guinea production was lower due to decline at the Okume Complex, partially offset by new production from the Ceiba Field. Crude oil production increased in 2012 compared with 2011 mainly due to the resumption of production in Libya, partly offset by lower production in Equatorial Guinea due to downtime and natural field decline.
Asia and Other: Crude oil production was lower in 2013 compared to 2012, mainly due to the sale in March 2013 of the Corporation’s interest in the Azeri-Chirag-Guneshli (ACG) fields in Azerbaijan. The assets were producing at a net rate of approximately 6,000 boepd at the time of sale. Natural gas production was lower in 2013 compared to 2012, mainly due to lower production entitlement at the Joint Development Area of Malaysia/Thailand (JDA) together with lower production at the Pangkah Field in Indonesia following the facility’s shutdown for planned maintenance in the second quarter of 2013. Natural gas production in 2012 was higher than 2011, primarily due to new wells at the Pangkah Field in Indonesia and a full year’s contribution from the Gajah Baru Complex at the Natuna A Field in Indonesia, which commenced production in the fourth quarter of 2011.
Sales Volumes: The Corporation’s worldwide sales volumes were as follows:
* Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. In addition, natural gas liquids do not sell at prices equivalent to crude oil. See the average selling prices on page 25.
Cost of Products Sold: Cost of products sold is mainly comprised of costs relating to the purchases of crude oil, natural gas liquids and natural gas from the Corporation’s partners in Hess operated wells or other third parties. The increase in Cost of products sold in the 2013 compared with 2012 and 2011 principally reflected higher volumes of crude oil purchases from third parties.
Cash Operating Costs: Cash operating costs, consisting of Operating costs and expenses, Production and severance taxes and General and administrative expenses, decreased by $201 million in 2013 compared with 2012 and increased by $401 million in 2012 compared with 2011. The decrease in 2013 was due to lower production taxes mainly due to the sale of the Corporation’s Russian operations, lower transportation costs, lower lease operating expenses and employee costs, partly offset by severance charges and other exit costs incurred as part of the Corporation’s transformation to a pure play E&P company. The increase in costs in 2012 reflects higher production taxes as a result of increased production volumes at the Bakken oil shale play and in Russia, together with higher operating and maintenance costs at the Valhall Field in Norway, the Llano Field, offshore U.S. in the Gulf of Mexico and the Bakken, onshore in the U.S.
Depreciation, Depletion and Amortization: Depreciation, depletion and amortization charges decreased by $182 million in 2013 and increased by $548 million in 2012, compared with the corresponding amounts in prior years. The decrease in 2013 primarily reflects asset sales and the mix of production volumes. The increase in 2012 was primarily due to higher volumes and per barrel costs associated with the assets that contributed the production growth.
Excluding items affecting comparability of earnings between periods in the table below, cash operating costs per barrel of oil equivalent were $22.63 in 2013, $20.63 in 2012 and $19.71 in 2011 and depreciation, depletion and amortization costs per barrel of oil equivalent were $21.61 in 2013, $19.20 in 2012 and $17.06 in 2011. Total production unit costs were $44.24 per boe in 2013, $39.83 per boe in 2012 and $36.77 per boe in 2011. Excluding assets sold, classified as held for sale, and any contribution from Libyan operations, pro forma total production unit costs for 2013 were $49.80 per boe.
For 2014, cash operating costs are estimated to be in the range of $20.50 to $21.50 per barrel and depreciation, depletion and amortization costs are estimated to be in the range of $29.00 to $30.00 per barrel, resulting in total production unit costs of $49.50 to $51.50 per barrel of oil equivalent assuming no contribution from Libya.
Exploration Expenses: Exploration expenses decreased in 2013 compared to 2012, primarily due to lower dry hole expenses and geological and seismic expenses partly offset by higher leasehold amortization expenses. Dry hole expenses in 2013 included an amount to write-off previously capitalized wells in Area 54, offshore Libya. Leasehold amortization expenses in 2013 included a charge to write-off the Corporation’s leasehold acreage in the Marcellus, onshore U.S. Exploration expenses decreased in 2012 compared to 2011, primarily due to lower dry hole expenses and lease amortization. Dry hole expenses in 2012 included amounts associated with two exploration wells, Ness Deep in the Gulf of Mexico and Ajek-1, offshore Indonesia.
Income Taxes: Excluding the impact of items affecting comparability of earnings between periods provided below, the effective income tax rates for E&P operations were 43% in 2013, 45% in 2012 and 38% in 2011. The decrease in the effective income tax rate in 2013 compared with 2012 was primarily due to the impact of shut-in production in Libya from the third quarter of 2013. The increase in the effective income tax rate in 2012 compared with 2011 was predominantly due to the resumption of Libyan operations, which were shut-in for substantially all of 2011. The effective income tax rate for E&P operations in 2014, excluding items affecting comparability of earnings, is estimated to be in the range of 37% to 41% assuming no contribution from Libya.
Items Affecting Comparability of Earnings Between Periods: Reported E&P earnings included the following items affecting comparability of income (expense) before and after income taxes:
* Amounts are net of the reversal of share-based compensation expense of $8 million ($7 million after income taxes) for expected stock grant forfeitures.
2013: In the fourth quarter, the Corporation announced the sale of its Indonesian assets for after-tax proceeds of approximately $1.3 billion. The sale was executed in two separate transactions with the sale of Natuna A completing in December 2013 and the sale of Pangkah closing in January 2014, as a result of a partner exercising their preemptive rights. The sale of Natuna A, which had sales proceeds of approximately $656 million, resulted in a pre-tax gain of $388 million ($343 million after income taxes). The Natuna Field was producing at an aggregate net rate of approximately 5,500 boepd at the time of sale and had a total of 21 million boe of proved reserves at December 31, 2012. The Corporation recorded a pre-tax asset impairment charge of $289 million ($187 million after income taxes) related to Pangkah to adjust its carrying value to its fair value at December 31, 2013. In April, the Corporation completed the sale of its Russian subsidiary, Samara-Nafta, for cash proceeds of $2.1 billion after working capital and other adjustments. Based on the Corporation’s 90% interest in Samara-Nafta, after-tax proceeds to Hess were approximately $1.9 billion. This transaction resulted in a nontaxable gain on
sale of $1,119 million, of which $168 million related to the noncontrolling interest holder’s share, resulting in a net gain attributable to the Corporation of $951 million. Samara-Nafta was producing at an aggregate net rate of approximately 50,000 boepd at the time of sale and had a total of 82 million boe of proved reserves at December 31, 2012. In the first quarter of 2013, the Corporation completed the sale of its interests in the Beryl fields in the UK North Sea for cash proceeds of $442 million, resulting in a pre-tax gain of $328 million ($323 million after income taxes) and the sale of its interests in the Azeri-Chirag-Guneshli (ACG) fields, offshore Azerbaijan in the Caspian Sea, for cash proceeds of $884 million, resulting in a pre-tax gain of $360 million ($360 million after income taxes). These assets were producing at an aggregate net rate of approximately 16,000 boepd at the time of sale and had a total of 38 million boe of proved reserves at December 31, 2012. See also Note 2, Dispositions in the notes to the Consolidated Financial Statements.
In December 2013, the Corporation recorded dry hole costs of $260 million ($163 million after income taxes) associated with Area 54, offshore Libya due to continued civil unrest in the country. The Corporation also recorded a pre-tax charge of $38 million ($23 million after income taxes) to write-off the Corporation’s leasehold acreage in the Marcellus, onshore U.S.
During 2013, the Corporation recorded net pre-tax charges of $129 million ($117 million after income taxes) for severance, non-cash charges associated with the cessation of use of certain leased office space and other exit costs, resulting from its planned divestitures and transformation into a more focused pure play E&P company. See also Note 4, Exit and Disposal Costs in the notes to the Consolidated Financial Statements.
In December 2013, Denmark enacted a new hydrocarbon income tax law that resulted in a combination of changes to tax rates, revisions to the amount of uplift allowed on capital expenditures and special transition rules. As a consequence of the tax law change, the Corporation recorded a deferred tax asset of $674 million. In addition, during 2013, the Corporation recorded a non-cash income tax charge of $28 million as a result of a planned asset divestiture and a charge of $22 million relating to the repatriation of foreign earnings.
2012: The Corporation completed the sale of its interests in the Schiehallion Field (Hess 16%) and the Bittern Field (Hess 28%), which are both located in the UK North Sea, as well as the Snohvit Field (Hess 3%), offshore Norway, for total cash proceeds of $843 million. These transactions resulted in pre-tax gains totaling $584 million ($557 million after income taxes). These assets were producing at an aggregate net rate of approximately 15,000 boepd at the time of sale and had a total of 83 million boe of proved reserves at December 31, 2011. See also Note 2, Dispositions in the notes to the Consolidated Financial Statements.
The Corporation recorded asset impairment charges totaling $582 million ($344 million after income taxes). These impairment charges consisted of $374 million ($228 million after income taxes) associated with the divestiture of assets in the Eagle Ford Shale in Texas and $208 million ($116 million after income taxes) related to non-producing properties in the UK North Sea.
During 2012, the Corporation decided to cease further development and appraisal activities in Peru. As a result, the Corporation recorded exploration expenses totaling $86 million ($56 million after income taxes) to write-off its exploration assets in the country.
In July 2012, the government of the UK changed the supplementary income tax rate applicable to deductions for dismantlement expenditures to 20% from 32%. As a result, the Corporation recorded a one-time charge in the third quarter of 2012 of $115 million for deferred taxes related to asset retirement obligations in the UK. In the fourth quarter of 2012, the Corporation recorded an income tax charge of $86 million for a disputed application of an international tax treaty.
2011: The Corporation completed the sale of its interests in certain natural gas producing assets in the UK North Sea, the Snorre Field (Hess 1%), offshore Norway, and the Cook Field (Hess 28%) in the UK North Sea for total cash proceeds of $490 million. These disposals resulted in pre-tax gains totaling $446 million ($413 million after income taxes). These assets had an aggregate net productive capacity of approximately 17,500 boepd at the time of sale.
In the third quarter of 2011, the Corporation recorded asset impairment charges of $358 million ($140 million after income taxes) related to increases in the Corporation’s estimated abandonment liabilities for non-producing properties.
In July 2011, the UK increased the supplementary tax rate on petroleum operations to 32% from 20%. As a result, the Corporation recorded a charge of $29 million to increase deferred tax liabilities in the UK.
Corporate and Interest
The following table summarizes corporate and interest expenses:
Corporate expenses were comparable in 2013, 2012 and 2011. After-tax corporate expenses in 2014 are estimated to be in the range of $125 million to $135 million, down from adjusted expenses excluding items affecting comparability provided below of $161 million in 2013.
The decrease in 2013 interest expense, net primarily reflects higher capitalized interest related to the Tubular Bells and North Malay Basin projects. The increase in 2012 interest expense, net principally reflects higher average debt and bank facility fees, partially offset by higher capitalized interest due to the sanctioning of the Tubular Bells project in September 2011. After-tax interest expense in 2014 is expected to be in the range of $225 million to $235 million, down from $255 million in 2013.
Items Affecting Comparability of Earnings Between Periods: Reported Corporate and Interest expenses included the following items affecting comparability of income (expense) before and after income taxes:
* Amounts are net of the reversal of share-based compensation expense of $8 million ($5 million after income taxes) for expected stock grant forfeitures.
During 2013, the Corporation recorded net pre-tax severance charges of $21 million ($13 million after income taxes) related to the Corporation’s transformation into a pure play E&P company. In addition, the Corporation incurred a pre-tax charge of $17 million ($11 million after income taxes) associated with the cessation of certain leased office space in 2013.
Downstream Businesses
Downstream businesses reported income of $1,189 million in 2013, income of $231 million in 2012 and a loss of $584 million in 2011. The downstream businesses comprise the Corporation’s retail, energy marketing, terminal, energy trading and refining operations. Excluding items affecting comparability of earnings between periods provided below, the downstream businesses generated earnings of $116 million in 2013, earnings of $160 million in 2012 and a loss of $59 million in 2011. These results reflect earnings from marketing operations and Port Reading refining activities which were permanently shut down in February 2013. In 2011, the Corporation’s share of HOVENSA’s results was a loss of $198 million.
Items Affecting Comparability of Earnings Between Periods: Reported earnings for the downstream businesses included the following items affecting comparability of income (expense) before and after income taxes:
* Amounts are net of the reversal of share-based compensation expense of $17 million ($10 million after income taxes) for expected stock grant forfeitures.
2013: In December 2013, the Corporation sold its U.S. East Coast terminal network, St. Lucia terminal and related businesses for cash proceeds of approximately $1.0 billion. The transaction resulted in a pre-tax gain of $739 million ($531 million after income taxes). In November 2013, the Corporation sold its energy marketing business for cash proceeds of approximately $1.2 billion which resulted in a pre-tax gain of $761 million ($464 million after income taxes). In addition, the Corporation recognized pre-tax gains of $678 million ($414 million after income taxes) relating to the liquidation of last-in, first-out (LIFO) inventories as a result of ceasing refining operations and the sales of its energy marketing and terminals businesses. During the year, the Corporation incurred $131 million ($80 million after income taxes) of net employee severance charges and $59 million ($36 million after income taxes) of other exit costs, including legal and professional fees. The Corporation also incurred charges of $173 million ($106 million after taxes) for legal, environmental, non-cash mark-to-market adjustments in energy marketing and other charges and $14 million for an income tax adjustment. As a result of the permanent shutdown of the Port Reading refining facility, the Corporation recorded charges of $82 million ($49 million after income taxes) for shutdown related costs and $80 million ($51 million after income taxes) for asset impairments.
2012: In 2012, the Corporation recorded pre-tax income of $165 million ($104 million after income taxes) from the partial liquidation of LIFO inventories. The Corporation also recorded pre-tax charges of $43 million ($33 million after income taxes) for asset impairments to certain marketing properties and other charges.
2011: The Corporation recorded a charge of $875 million ($525 million after income taxes) due to the impairment recorded by HOVENSA and other charges associated with its decision to shut down the refinery. The Corporation’s share of the impairment related losses recorded by HOVENSA represented an amount equivalent to the Corporation’s financial support to HOVENSA at December 31, 2011, its planned future funding commitments for costs related to the refinery shutdown, and a charge of $135 million for the write-off of related assets held by the subsidiary which owns the Corporation’s investment in HOVENSA. A deferred income tax benefit of $350 million, consisting primarily of U.S. income taxes, was recorded on the Corporation’s share of HOVENSA’s impairment and refinery shutdown related charges.
Liquidity and Capital Resources
The following table sets forth certain relevant measures of the Corporation’s liquidity and capital resources at December 31:
* Total debt as a percentage of the sum of total debt plus equity.
Cash Flows
The following table sets forth a summary of the Corporation’s cash flows:
Operating Activities: Net cash provided by operating activities amounted to $4,870 million in 2013 compared with $5,660 million in 2012, reflecting decreases in cash flows from changes in working capital. Operating cash flow increased to $5,660 million in 2012 from $4,984 million in 2011 principally reflecting higher operating earnings and increases in cash flows from changes in working capital.
Investing Activities: The following table summarizes the Corporation’s capital expenditures:
The decrease in capital expenditures in 2013 as compared to 2012 was mainly due to reduced capital expenditures in the Bakken, resulting from fewer drilling rigs being operated in the field as well as lower costs per well, and at the Valhall Field following the completion of the redevelopment project in January 2013 as well as asset sales. The increased spend on capital expenditures in 2012 compared to 2011 primarily reflected additional spending at the Bakken oil shale play as a result of more drilling rigs operated in the field, higher working interest wells and increased spending on field infrastructure projects. Capital expenditures in 2011 included acquisitions of approximately $800 million for 195,000 net acres in the Utica Shale play in Ohio, $214 million for interests in two blocks in the Kurdistan Region of Iraq and $116 million for an additional 4% interest in the South Arne Field in Denmark.
Total proceeds from the sale of E&P assets was approximately $4.5 billion in 2013, $843 million in 2012 and $490 million in 2011. Completed sales in 2013 included the Corporation’s interests in the Beryl, ACG, Eagle Ford and Natuna A fields, its Russian subsidiary, Samara-Nafta, and proceeds of approximately $2.2 billion from the sale of the Corporation’s energy marketing operations and its U.S. East Coast terminal network, St. Lucia terminal and related businesses.
Financing Activities: During 2013, the Corporation repaid a net amount of $2,348 million under available credit facilities and repaid $136 million of other debt. The net repayments under the credit facilities consisted of $990 million on the Corporation’s short-term credit facilities, $758 million on its syndicated revolving credit facility and $600 million on its asset backed credit facility. During 2012, the Corporation borrowed a net of $1,845 million from available credit facilities, which consisted of borrowings of $758 million from its syndicated revolving credit facility, $890 million from its short-term credit facilities and $250 million from its asset-backed credit facility, partially offset by net repayments of other debt of $53 million. During 2011, net borrowings on available credit facilities were $422 million.
In 2013, the Corporation used approximately $1.5 billion of cash from the proceeds of its asset divestiture program, for the repurchase of common shares under a board authorized $4 billion repurchase plan. Total common stock dividends paid were $235 million in 2013, $171 million in 2012 and $136 million in 2011. In the third quarter of 2013, the Corporation increased its quarterly dividend to $0.25 per common share, from $0.10 per share. In 2012, the Corporation made five quarterly common stock dividend payments as a result of accelerating payment of the fourth quarter 2012 dividend, which historically would have been paid in the first quarter of 2013. The Corporation received net proceeds from the exercise of stock options, including related income tax benefits of $128 million, $11 million and $88 million in 2013, 2012 and 2011, respectively.
Future Capital Requirements and Resources
The Corporation anticipates investing a total of approximately $5.8 billion in capital and exploratory expenditures during 2014 for E&P operations and approximately $350 million for retail marketing primarily for the acquisition of its partner’s interest in the WilcoHess joint venture. The Corporation expects to fund its 2014 projected cash flow deficit, including capital expenditures, dismantlement obligations, dividends, pension contributions, debt repayments and share repurchases under its Board authorized plan, with existing cash on-hand, cash flows from operations and proceeds from asset sales. Looking forward, the Corporation expects its continued production growth, driven largely by the Bakken, Valhall and Tubular Bells, to generate free cash flow post 2014 at $100 Brent prices.
Crude oil and natural gas prices are volatile and difficult to predict. In addition, unplanned increases in the Corporation’s capital expenditure program could occur. If conditions were to change, such as a significant decrease in commodity prices or an unexpected increase in capital expenditures, the Corporation would take steps to protect its financial flexibility and may pursue other sources of liquidity, including discontinuing stock repurchases, reducing its planned capital program, utilizing existing credit facilities, issuing debt and equity securities, and/or further asset sales.
The table below summarizes the capacity, usage, and available capacity of the Corporation’s borrowing and letter of credit facilities at December 31, 2013:
* Committed and uncommitted lines have expiration dates through 2015.
The Corporation’s $410 million in letters of credit outstanding at December 31, 2013 were primarily issued to satisfy margin requirements. See also Note 23, Risk Management and Trading Activities in the notes to the Consolidated Financial Statements.
The Corporation has a $4 billion syndicated revolving credit facility that matures in April 2016. This facility can be used for borrowings and letters of credit. Borrowings on the facility bear interest at 1.25% above the London Interbank Offered Rate. A fee of 0.25% per annum is also payable on the amount of the facility. The interest rate and facility fee are subject to
adjustment if the Corporation’s credit rating changes. The Corporation also had a 364 day asset-backed-credit facility, which was terminated in September 2013.
The Corporation’s long-term debt agreements, including the revolving credit facility, contain financial covenants that restrict the amount of total borrowings and secured debt. At December 31, 2013, the Corporation is permitted to borrow up to an additional $35.5 billion for the construction or acquisition of assets. The Corporation has the ability to borrow up to an additional $5.9 billion of secured debt at December 31, 2013.
The Corporation also has a shelf registration under which it may issue additional debt securities, warrants, common stock or preferred stock.
Credit Ratings
There are three major credit rating agencies that rate the Corporation’s debt. All three agencies have currently assigned an investment grade rating with a stable outlook to the Corporation’s debt. The interest rates and facility fees charged on some of the Corporation’s credit facilities, as well as margin requirements from risk management and trading counterparties, are subject to adjustment if the Corporation’s credit rating changes.
Contractual Obligations and Contingencies
The following table shows aggregate information about certain contractual obligations at December 31, 2013:
* At December 31, 2013, the Corporation’s debt bears interest at a weighted average rate of 6.1%.
Supply commitments include term purchase agreements at market prices for a portion of the gasoline necessary to supply the Corporation’s retail marketing system. In addition, the Corporation has commitments to purchase refined petroleum products, natural gas and electricity on behalf of Direct Energy to supply contracted customers from its divested energy marketing business until the customer contracts transfer to Direct Energy, which is expected to be substantially complete in the first half of 2014. See
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
In the normal course of its business, the Corporation is exposed to commodity risks related to changes in the prices of crude oil, natural gas, refined petroleum products and electricity, as well as to changes in interest rates and foreign currency values. In the disclosures that follow, risk management activities are referred to as corporate risk management activities. The Corporation also has trading operations, through a 50% voting interest in a consolidated partnership, that trades energy-related commodities, securities and derivatives. These activities are also exposed to commodity risks primarily related to the prices of crude oil, natural gas, refined petroleum products and electricity. The following describes how these risks are controlled and managed.
In November 2013, the Corporation completed the sale of its energy marketing business to Direct Energy, a North American subsidiary of Centrica plc (Centrica). Certain derivative contracts, including new transactions following the closing date, (the “delayed transfer derivative contracts”) have not been transferred to Direct Energy, as required customer or regulatory consents have not been obtained. However, the agreement entered into between Hess and Direct Energy on the closing date transfers all economic risks and rewards of the energy marketing business, including the ownership of the
delayed transfer derivative contracts, to Direct Energy. As a result, the assets and liabilities related to the delayed transfer derivative contracts remain on the Corporation’s Consolidated Balance Sheet at December 31, 2013 but changes in their fair value are offset based on the terms of the agreement between Hess and Direct Energy. The Corporation therefore has no market risk related to these delayed transfer derivative contracts and only retains credit risk exposure, which has been guaranteed by Centrica. It is expected that the transfer of these contracts will be substantially complete in the first half of 2014.
Controls: The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include volumetric, term and value at risk limits. The chief risk officer must approve the trading of new instruments or commodities. Risk limits are monitored and are reported on a daily basis to business units and senior management. The Corporation’s risk management department also performs independent price verifications (IPV’s) of sources of fair values and validations of valuation models. These controls apply to all of the Corporation’s risk management and trading activities, including the consolidated trading partnership. The Corporation’s treasury department is responsible for administering and monitoring foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable.
The Corporation uses value at risk to monitor and control commodity risk within its risk management and trading activities. The value at risk model uses historical simulation and the results represent the potential loss in fair value over one day at a 95% confidence level. The model captures both first and second order sensitivities for options. Results may vary from time to time as strategies change in trading activities or hedging levels change in risk management activities.
Instruments: The Corporation primarily uses forward commodity contracts, foreign exchange forward contracts, futures, swaps, options and energy commodity based securities in its risk management and trading activities. These contracts are generally widely traded instruments with standardized terms. The following describes these instruments and how the Corporation uses them:
•
Forward Commodity Contracts: The Corporation enters into contracts for the forward purchase and sale of commodities. At settlement date, the notional value of the contract is exchanged for physical delivery of the commodity. Forward contracts that are deemed normal purchase and sale contracts are excluded from the quantitative market risk disclosures.
•
Forward Foreign Exchange Contracts: The Corporation enters into forward contracts, primarily for the British Pound and the Thai Baht, which commit the Corporation to buy or sell a fixed amount of these currencies at a predetermined exchange rate on a future date.
•
Exchange Traded Contracts: The Corporation uses exchange traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position limits.
•
Swaps: The Corporation uses financially settled swap contracts with third parties as part of its risk management and trading activities. Cash flows from swap contracts are determined based on underlying commodity prices or interest rates and are typically settled over the life of the contract.
•
Options: Options on various underlying energy commodities include exchange traded and third party contracts and have various exercise periods. As a seller of options, the Corporation receives a premium at the outset and bears the risk of unfavorable changes in the price of the commodity underlying the option. As a purchaser of options, the Corporation pays a premium at the outset and has the right to participate in the favorable price movements in the underlying commodities.
•
Energy Securities: Energy securities include energy-related equity or debt securities issued by a company or government or related derivatives on these securities.
Corporate Risk Management Activities
Corporate risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas produced by the Corporation or to reduce exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to reduce risk in the selling price of a portion of the Corporation’s crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which the Corporation does
business with the intent of reducing exposure to foreign currency fluctuations. Interest rate swaps may also be used, generally to convert fixed-rate interest payments to floating.
The Corporation has entered into Brent crude oil fixed price swap contracts to hedge 25,000 boepd for calendar year 2014 at an average price of $109.12 per barrel. The Corporation has outstanding foreign exchange contracts used to reduce its exposure to fluctuating foreign exchange rates for various currencies. The change in fair value of foreign exchange contracts from a 10% strengthening of the U.S. Dollar exchange rate is estimated to be a gain of approximately $4 million at December 31, 2013.
The Corporation’s outstanding long-term debt of $5,798 million, including current maturities, had a fair value of $6,641 million at December 31, 2013. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $160 million at December 31, 2013. A 15% increase in the rate of interest would decrease the fair value of debt by approximately $150 million at December 31, 2013.
Following is the value at risk for the Corporation’s risk management commodity derivatives activities associated with continuing operations, excluding foreign exchange and interest rate derivatives described above:
The increase in the value at risk for the Corporation’s risk management commodity derivatives activities at December 31, 2013 is primarily due to the new Brent crude oil cash flow hedge positions entered in December 2013 as described in Note 23, Risk Management and Trading Activities in the notes to the Consolidated Financial Statements.
Trading Activities
Trading activities are conducted through a trading partnership in which the Corporation has a 50% voting interest that is currently for sale. The partnership intends to generate earnings through various strategies primarily using energy related commodities, securities and derivatives.
Following is the value at risk for the Corporation’s trading activities:
The information that follows represents 100% of the trading partnership. Derivative trading transactions are marked-to-market and unrealized gains or losses are recognized currently in earnings. Gains or losses from sales of physical products are recorded at the time of sale. Net realized gains on trading activities amounted to $191 million in 2013 and $60 million in 2012. The following table provides an assessment of the factors affecting the changes in fair value of net assets (liabilities) relating to financial instruments and derivative commodity contracts used in trading activities:
The following table summarizes the sources of net asset (liability) fair values of financial instruments and derivative commodity contracts by year of maturity used in the Corporation’s trading activities at December 31, 2013:
The following table summarizes the fair values of receivables net of cash margin and letters of credit relating to the Corporation’s trading activities and the credit ratings of counterparties at December 31:
* Based on information provided by counterparties and other available sources.
Item 8. Financial Statements and Supplementary Data
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
* Schedules other than Schedule II have been omitted because of the absence of the conditions under which they are required or because the required information is presented in the financial statements or the notes thereto.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework). Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2013.
The Corporation’s independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2013, as stated in their report, which is included herein.
By
/s/ John P. Rielly
By
/s/ John B. Hess
John P. Rielly
Senior Vice President and
Chief Financial Officer
John B. Hess
Chief Executive Officer
February 28, 2014
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
We have audited Hess Corporation and consolidated subsidiaries’ (the “Corporation”) internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). The Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Hess Corporation and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Hess Corporation and consolidated subsidiaries as of December 31, 2013 and 2012, and the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2013 of Hess Corporation and consolidated subsidiaries, and our report dated February 28, 2014 expressed an unqualified opinion thereon.
/S/ ERNST & YOUNG LLP
February 28, 2014
New York, New York
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
We have audited the accompanying consolidated balance sheet of Hess Corporation and consolidated subsidiaries (the “Corporation”) as of December 31, 2013 and 2012, and the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Hess Corporation and consolidated subsidiaries at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hess Corporation’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 28, 2014 expressed an unqualified opinion thereon.
/S/ ERNST & YOUNG LLP
February 28, 2014
New York, New York
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and production activities.
See accompanying notes to consolidated financial statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED INCOME
See accompanying notes to the consolidated financial statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
See accompanying notes to the consolidated financial statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
See accompanying notes to consolidated financial statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED EQUITY
See accompanying notes to consolidated financial statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Nature of Business: Hess Corporation 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 and natural gas. Prior to 2013, the Corporation also operated a Marketing and Refining (M&R) segment, which it began to divest during the year. The M&R businesses manufacture refined petroleum products and purchase, market, store and trade refined products, natural gas and electricity, as well as operate retail gas stations, most of which have convenience stores. See also Note 21, Segment Information in the notes to the Consolidated Financial Statements for a description of the Corporation’s reportable segments at December 31, 2013.
In the first quarter of 2013, the Corporation announced several initiatives to continue its transformation into a more focused pure play E&P company. The transformation plan included fully exiting the Corporation’s M&R businesses, including its terminal, retail, energy marketing and energy trading operations, as well as the permanent shutdown of refining operations at its Port Reading facility, thus completing its exit from all refining operations. 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 United States (U.S.) Virgin Islands refinery in January 2012 and continued operating solely as an oil storage terminal. HOVIC and its partner have also commenced a sales process for HOVENSA. The transformation plan also committed to the sale of mature E&P assets in Indonesia and Thailand and the pursuit of monetizing Bakken midstream assets by 2015. See also Note 2, Dispositions and Note 24, Subsequent Events in the notes to the Consolidated Financial Statements for a description of the divestitures completed to date under this transformation plan.
Principles of Consolidation and Basis of Presentation: The consolidated financial statements include the accounts of Hess Corporation and entities in which the Corporation owns more than a 50% voting interest or entities that the Corporation controls. The Corporation consolidates the trading partnership in which it owns a 50% voting interest and over which it exercises control. The Corporation’s undivided interests in unincorporated oil and gas exploration and production ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where the Corporation has the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method.
The 2012 and 2011 financial information has been recast so that the basis of presentation is consistent with that of the 2013 financial information which reflects the results of operations and cash flows of the Corporation’s divested downstream businesses as discontinued operations for all periods presented (See Note 3, Discontinued Operations in the notes to the Consolidated Financial Statements). Certain other information in the financial statements and notes has been reclassified to conform to the current period presentation. In the preparation of these financial statements, the Corporation has evaluated subsequent events through the date of issuance.
Estimates and Assumptions: In preparing financial statements in conformity with U.S. generally accepted accounting principles (GAAP), management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income. Actual results could differ from those estimates. Estimates made by management include oil and gas reserves, asset and other valuations, depreciable lives, pension liabilities, legal and environmental obligations, asset retirement obligations and income taxes.
Revenue Recognition: The Corporation recognizes revenues from the sale of crude oil, natural gas, refined petroleum products and other merchandise when title passes to the customer. Sales are reported net of excise and similar taxes in the Statement of Consolidated Income. The Corporation recognizes revenues from the production of natural gas properties based on sales to customers. Differences between E&P natural gas volumes sold and the Corporation’s share of natural gas production are not material.
In its E&P activities, the Corporation engages in crude oil purchase and sale transactions with the same counterparty that are entered into in contemplation of one another for the primary purpose of changing location or quality. Similarly, in its marketing activities, the Corporation enters into refined petroleum product purchase and sale transactions with the same counterparty. These arrangements are reported net in Sales and other operating revenues in the Statement of Consolidated Income.
Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. In production operations, costs of injected CO2 for tertiary recovery are expensed as incurred.
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors.
Depreciation, Depletion and Amortization: The Corporation records depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production equipment and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives. Retail gas stations and equipment related to leased properties, are depreciated over the estimated useful lives not to exceed the remaining lease period.
Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying assets.
Impairment of Long-lived Assets: The Corporation reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted future cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market-based valuation approach, which are Level 3 fair value measurements. In the case of oil and gas fields, the net present value of future cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from the average prices used in the standardized measure of discounted future net cash flows.
Impairment of Equity Investees: The Corporation reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value may have occurred. The fair value measurement used in the impairment assessment is based on quoted market prices, where available, or other valuation techniques, including discounted cash flows.
Impairment of Goodwill: The Corporation’s goodwill is assigned to the E&P operating segment. Goodwill is tested for impairment annually in the fourth quarter or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable. This impairment test is performed at the reporting unit level, which accounting standards define as an operating segment or one level below an operating segment. Following a reorganization of its management structure in 2013, the Corporation determined its reporting units are its onshore and offshore businesses and tests for impairment by comparing the fair value of each reporting unit to its book value, including goodwill. If the fair value of a reporting unit exceeds the carrying amount, goodwill is not impaired. If the carrying value exceeds the fair value, the Corporation calculates the possible impairment loss by comparing the implied fair value of goodwill with the carrying amount. If the implied fair value of goodwill is less than the carrying amount, an impairment would be recorded.
Cash and Cash Equivalents: Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have maturities of three months or less when acquired.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Inventories: Inventories are valued at the lower of cost or market. For refined petroleum product inventories valued at cost, the Corporation uses principally the last-in, first-out (LIFO) inventory method. For the remaining inventories, cost is generally determined using average actual costs.
Income Taxes: Deferred income taxes are determined using the liability method. The Corporation regularly assesses the realizability of deferred tax assets, based on estimates of future taxable income, the availability of tax planning strategies, the existence of appreciated assets, the available carryforward periods for net operating losses and other factors. If it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount expected to be realized. In addition, the Corporation recognizes the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. Additionally, the Corporation has income taxes which have been deferred on intercompany transactions eliminated in consolidation related to transfers of property, plant and equipment remaining within the consolidated group. The amortization of these income taxes deferred on intercompany transactions will occur ratably with the recovery through depletion and depreciation of the carrying value of these assets. The Corporation does not provide for deferred U.S. income taxes for that portion of undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations. The Corporation classifies interest and penalties associated with uncertain tax positions as income tax expense.
Asset Retirement Obligations: The Corporation has material legal obligations to remove and dismantle long-lived assets and to restore land or seabed at certain exploration and production locations. The Corporation recognizes a liability for the fair value of legally required asset retirement obligations associated with long-lived assets in the period in which the retirement obligations are incurred. In addition, the fair value of any legally required conditional asset retirement obligations is recorded if the liability can be reasonably estimated. The Corporation capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets.
Retirement Plans: The Corporation recognizes the funded status of defined benefit postretirement plans in the Consolidated Balance Sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. The Corporation recognizes the net changes in the funded status of these plans in the year in which such changes occur. Prior service costs and actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service period of active employees.
Derivatives: The Corporation utilizes derivative instruments for both risk management and trading activities. In risk management activities, the Corporation uses futures, forwards, options and swaps, individually or in combination, to mitigate its exposure to fluctuations in prices of crude oil, natural gas, refined petroleum products and electricity, as well as changes in interest and foreign currency exchange rates. The Corporation, through a consolidated partnership, trades energy-related commodities and derivatives, including futures, forwards, options and swaps based on expectations of future market conditions.
All derivative instruments are recorded at fair value in the Corporation’s Consolidated Balance Sheet. The Corporation’s policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges) or hedges of firm commitments (fair value hedges). The effective portion of changes in fair value of derivatives that are designated as cash flow hedges is recorded as a component of other comprehensive income (loss) while the ineffective portion of the changes in fair value is recorded currently in earnings. Amounts included in Accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements: The Corporation uses various valuation approaches in determining fair value, including the market and income approaches. The Corporation’s fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and the Corporation’s credit is considered for accrued liabilities.
The Corporation also records certain nonfinancial assets and liabilities at fair value when required by GAAP. These fair value measurements are recorded in connection with business combinations, qualifying nonmonetary exchanges, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments or goodwill.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Corporation determines fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2.
When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. To value derivatives that are characterized as Level 2 and 3, the Corporation uses observable inputs for similar instruments that are available from exchanges, pricing services or broker quotes. These observable inputs may be supplemented with other methods, including internal extrapolation or interpolation, that result in the most representative prices for instruments with similar characteristics. Multiple inputs may be used to measure fair value, however, the level of fair value for each physical derivative and financial asset or liability is based on the lowest significant input level within this fair value hierarchy.
Details on the methods and assumptions used to determine the fair values are as follows:
Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. The fair value of certain of the Corporation’s exchange traded futures and options are considered Level 1.
Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. The Corporation utilizes fair value measurements based on Level 2 inputs for certain forwards, swaps and options.
Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. For example, the Corporation entered into contracts to sell natural gas and electricity to customers and offsets the price exposure by purchasing forward contracts. The fair value of these sales and purchases may be based on specific prices at less liquid delivered locations, which are classified as Level 3. There may be offsets to these positions that are priced based on more liquid markets, which are, therefore, classified as Level 1 or Level 2. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3.
Share-based Compensation: The fair value of all share-based compensation is recognized as expense on a straight-line basis over the full vesting period of the awards. The Corporation estimates the fair value of employee stock options at the date of grant using a Black-Scholes valuation model, performance share units using a Monte Carlo simulation model, and restricted stock based on the market value of the underlying shares at the date of grant.
Foreign Currency Translation: The U.S. Dollar is the functional currency (primary currency in which business is conducted) for most foreign operations. Adjustments resulting from translating monetary assets and liabilities that are denominated in a non-functional currency into the functional currency are recorded in Other, net in the Statement of Consolidated Income. For operations that do not use the U.S. Dollar as the functional currency, adjustments resulting from translating foreign currency assets and liabilities into U.S. Dollars are recorded in a separate component of equity titled Accumulated other comprehensive income (loss).
Maintenance and Repairs: Maintenance and repairs are expensed as incurred. Capital improvements are recorded as additions in Property, plant and equipment.
Environmental Expenditures: The Corporation accrues and expenses environmental costs on an undiscounted basis to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. The Corporation capitalizes environmental expenditures that increase the life or efficiency of property or reduce or prevent future adverse impacts to the environment.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Changes in Accounting Policies: Effective January 1, 2013, the Corporation adopted ASU 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (AOCI) which requires aggregated disclosures of amounts reclassified out of AOCI as well as a presentation of changes in AOCI balances by component. The changes in AOCI by component, including amounts reclassified out of AOCI in their entirety are presented in the Statement of Consolidated Comprehensive Income.
Effective January 1, 2013, the Corporation adopted ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities which requires disclosure of information needed to evaluate the effects or potential effects of the contractual right of setoff for assets and liabilities. This accounting standard update applies to assets and liabilities related to financial instruments and derivatives subject to an enforceable master netting arrangement or similar agreement. The required disclosures are presented in Note 23, Risk Management and Trading Activities.
2. Dispositions
Exploration and Production
2013: In December, the Corporation completed the sale of its interest in the Natuna A Field, offshore Indonesia for total cash proceeds of approximately $656 million. The transaction resulted in a pre-tax gain of $388 million ($343 million after income taxes), after deducting the net book value of assets including allocated goodwill of $39 million.
In April, the Corporation completed the sale of 100% of its Russian subsidiary, Samara-Nafta for cash proceeds of approximately $2.1 billion. Based on its 90% interest in Samara-Nafta, total after-tax proceeds to the Corporation were approximately $1.9 billion after working capital and other adjustments. The transaction resulted in a nontaxable gain of $1,119 million after deducting the net book value of assets, including allocated goodwill of $148 million. After reduction of the noncontrolling interest holder’s share of $168 million, which is reflected in Net income (loss) attributable to noncontrolling interests, the net gain attributable to the Corporation was $951 million.
In March, the Corporation sold its interests in the Azeri-Chirag-Guneshli (ACG) fields (Hess 3%), offshore Azerbaijan in the Caspian Sea, and the associated Baku-Tbilisi-Ceyhan (BTC) oil transportation pipeline company (Hess 2%) for cash proceeds of $884 million. The transaction resulted in a pre-tax gain of $360 million ($360 million after income taxes), after deducting the net book value of assets including allocated goodwill of $52 million.
In January, the Corporation completed the sale of its interests in the Beryl fields and the Scottish Area Gas Evacuation System (SAGE) in the UK North Sea for cash proceeds of $442 million. The transaction resulted in a pre-tax gain of $328 million, ($323 million after income taxes), after deducting the net book value of assets including allocated goodwill of $48 million.
2012: In October, the Corporation completed the sale of its interests in the Bittern Field (Hess 28%) in the UK North Sea and the associated Triton floating production, storage and offloading vessel for cash proceeds of $187 million. The transaction resulted in an after-tax gain of $172 million, after deducting the net book value of assets including allocated goodwill of $12 million.
In September, the Corporation completed the sale of its interests in the Schiehallion Field (Hess 16%) in the UK North Sea, its share of the associated floating production, storage and offloading vessel, and the West of Shetland pipeline system for cash proceeds of $524 million. The transaction resulted in a pre-tax gain of $376 million ($349 million after income taxes), after deducting the net book value of assets including allocated goodwill of $27 million.
In January, the Corporation completed the sale of its interest in the Snohvit Field (Hess 3%), a liquefied natural gas project, offshore Norway, for cash proceeds of $132 million. The transaction resulted in an after-tax gain of $36 million, after deducting the net book value of assets including allocated goodwill of $14 million.
2011: In February, the Corporation completed the sale of its interests in certain natural gas producing assets in the UK North Sea for cash proceeds of $359 million. These disposals resulted in pre-tax gains totaling $343 million ($310 million after income taxes). In August, the Corporation completed the sale of its interests in the Snorre Field (Hess 1%), offshore Norway and the Cook Field (Hess 28%) in the UK North Sea for cash proceeds of $131 million. These disposals resulted in after-tax gains totaling $103 million.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Discontinued Operations
2013: In December, the Corporation completed the sale of its U.S. East Coast terminal network, St. Lucia terminal and related businesses for cash proceeds of approximately $1.0 billion, which generated a pre-tax gain of $739 million ($531 million after income taxes), after deducting the net book value of assets. In November, the Corporation completed the sale of its energy marketing business for cash proceeds of approximately $1.2 billion, which generated a pre-tax gain of $761 million ($464 million after income taxes).
3. Discontinued Operations
As a result of the Corporation’s divestiture of its energy marketing business and terminals network and its cessation of refining at the Port Reading facility, the results of operations for these businesses have been reported as discontinued operations in the Statement of Consolidated Income for all periods presented. These businesses were previously included in the M&R segment.
Sales and other operating revenues and Income from discontinued operations were as follows:
* In 2013, Income from discontinued operations included pre-tax gains on asset sales of $1,500 million ($995 million after income taxes).
The Corporation’s retail marketing business and energy trading joint venture have been classified as continuing operations for all periods presented as the Corporation is contemplating different methods of disposal and is experiencing lengthy marketing processes. There was no material impact to the results of operations as a result of these re-classifications for any period presented. The retail marketing business and energy trading joint venture will be classified as discontinued operations when these businesses are divested.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
4. Exit and Disposal Costs
The following table provides the components of and changes in the Corporation’s restructuring accruals:
(a) Amounts are before the reversal of approximately $33 million of share-based compensation expense related to grants that are expected to be forfeited.
(b) Of the total employee severance charges for 2013, $22 million was included in Operating costs and expenses, $19 million in Exploration expenses, $40 million in Marketing expenses, $63 million in General and administrative expenses and $108 million in Income from discontinued operations.
(c) Included $37 million in General and administrative expenses, $16 million in Depreciation, depletion and amortization, $1 million in Operating costs and expenses and $8 million in Other, net.
(d) Included in Marketing expenses.
(e) Included in General and administrative expenses.
(f) Included in Income from discontinued operations.
The employee severance charges primarily resulted from the Corporation’s divestiture program announced in March 2013, which was initiated to continue its transformation to a more focused pure play E&P company. The severance charges were based on probable amounts incurred under ongoing severance arrangements or other statutory requirements, plus amounts earned through December 31, 2013 under enhanced benefit arrangements. The expense associated with the enhanced benefits is recognized ratably over the estimated service period required for the employee to earn the benefit upon termination.
The Corporation expects to incur additional enhanced benefit charges of approximately $30 million beyond the amounts accrued at December 31, 2013, of which $5 million relates to E&P, $10 million to Retail Marketing and Other, $10 million to Corporate and $5 million to discontinued operations. The Corporation’s estimate of employee severance costs could change due to a number of factors, including the number of employees that work through the requisite service date and the timing of when each remaining divestiture occurs.
The facility and other exit costs relate to the shutdown of Port Reading refining operations, charges associated with the cessation of use of certain leased office space, contract termination costs and professional fees associated with the divestitures.
5. Acquisitions
In 2011, the Corporation entered into agreements to acquire approximately 85,000 net acres in the dry gas area of the Utica Shale play in Ohio for approximately $750 million, principally through the acquisition of Marquette Exploration, LLC (Marquette). The acquisition of Marquette was accounted for as a business combination and the assets acquired and the liabilities assumed were recorded at fair value. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The majority of the purchase price
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
was assigned to unproved properties and the remainder to producing wells and working capital. See Note 24, Subsequent Events in the notes to the Consolidated Financial Statements for the divestiture of dry gas acreage.
Also in 2011, the Corporation completed the acquisition of a 50% undivided interest in CONSOL Energy Inc.’s (CONSOL) approximately 200,000 acres, in the Utica Shale play in Ohio, for $59 million in cash at closing and the agreement to fund 50% of CONSOL’s share of the drilling costs up to $534 million within a 5-year period. This transaction was accounted for as an asset acquisition. During the second quarter of 2013, the Corporation reached an agreement with CONSOL relating to its ongoing title verification efforts, which reduced the gross joint venture acreage by approximately 64,000 acres, to approximately 146,000 acres, and the total carry obligation to $335 million, from $534 million. At December 31, 2013, the Corporation’s remaining carry obligation was approximately $200 million.
6. Inventories
Inventories at December 31 were as follows:
The percentage of last-in, first-out (LIFO) inventories to total crude oil, refined petroleum products and natural gas inventories was 43% and 71% at December 31, 2013 and 2012, respectively. During 2013 and 2012, the Corporation reduced LIFO inventories, which are carried at lower costs than current inventory costs, resulting in gains of $678 million ($414 million after income taxes) and $165 million ($104 million after income taxes), respectively, that were all classified in Income from discontinued operations. Inventories related to the E&P segment were $599 million at December 31, 2013 and $738 million at December 31, 2012.
7. Property, Plant and Equipment
Property, plant and equipment at December 31 were as follows:
Assets Held for Sale: In March 2013, the Corporation approved a plan to divest its E&P assets in Thailand (comprising the Pailin (Hess 15%) and Sinphuhorm (Hess 35%) fields) and the Pangkah Field, offshore Indonesia (Hess 75%). At December 31, 2013, the book value of assets associated with these properties totaling $1,097 million, primarily consisting of the net property, plant and equipment balances as well as allocated goodwill of $76 million, were reported as assets held for sale. In addition, liabilities related to these properties totaling $286 million, primarily consisting of asset retirement obligations and deferred income taxes, were reported in liabilities associated with assets held for sale. At December 31,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2012, assets totaling $1,092 million, including allocated goodwill of $100 million, and liabilities totaling $539 million that were related to the ACG and Beryl fields, which were divested in the first quarter of 2013, were reported as held for sale. Properties classified as held for sale are not depreciated but are subject to impairment testing.
Capitalized Exploratory Wells Costs: The following table discloses the amount of capitalized exploratory well costs pending determination of proved reserves at December 31, and the changes therein during the respective years:
In 2013, capitalized well costs reclassified based on the determination of proved reserves primarily related to the Shenzi project in the Gulf of Mexico. Capitalized exploratory well costs charged to expense in 2013 in the preceding table include $260 million to write-off previously capitalized exploration wells in Area 54, offshore Libya, due to civil unrest. The preceding table excludes exploratory dry hole costs of $77 million, $248 million and $348 million in 2013, 2012 and 2011, respectively, which were incurred and subsequently expensed in the same year.
At December 31, 2013, exploratory drilling costs capitalized in excess of one year past completion of drilling were incurred as follows (in millions):
The capitalized well costs in excess of one year relate to 8 projects. Approximately 45% relates to Block WA-390-P, offshore Western Australia, where development planning and commercial activities, including negotiations with potential liquefaction partners, are ongoing. Successful negotiation with a third party liquefaction partner is necessary before the Corporation can negotiate a gas sales agreement and sanction development of the project. Approximately 27% relates to the Corporation’s Pony discovery on Block 468 in the deepwater Gulf of Mexico, and 8% relates to the Pony #3 well on Block 469. The Corporation has signed an exchange agreement with the partners of the adjacent Green Canyon Blocks 512 and 511, which contain the Knotty Head discovery. Under this agreement, Hess was appointed operator and has a 20% working interest in the blocks, which are now collectively referred to as the Stampede project. An application to unitize Blocks 468, 512, the western half of 469 and the eastern half of 511 is due to be filed with the Bureau of Safety and Environmental Enforcement in the first quarter of 2014. Field development planning is progressing and the project is targeted for sanction in 2014. Approximately 16% relates to offshore Ghana where the Corporation has drilled seven successful exploration wells. Appraisal plans for the seven wells on the block were submitted to the Ghanaian government for approval in June 2013 and by year-end four had been approved. The Corporation plans to commence a three well appraisal drilling program in the second half of 2014. The remainder of the capitalized well costs in excess of one year relates to projects where further drilling is planned or development planning and other assessment activities are ongoing to determine the economic and operating viability of the projects.
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8. Goodwill
The changes in the carrying amount of goodwill, all of which relate to the E&P segment, are as follows:
* Includes $76 million and $52 million reclassified to Assets held for sale in 2013 and 2012, respectively.
9. Asset Impairments
During the fourth quarter of 2013, the Corporation announced the sale of its E&P assets in Indonesia for approximately $1.3 billion. The sale was executed in two separate transactions, with Natuna A completing in December 2013 and Pangkah in January 2014, as a result of a partner exercising their preemptive rights. Based on the sales proceeds for each transaction, fourth quarter 2013 results included a pre-tax gain on asset sale related to Natuna A of $388 million ($343 million after income taxes), and a pre-tax asset impairment charge of $289 million ($187 million after income taxes) to adjust the carrying value of the Pangkah assets to their fair value at December 31, 2013.
During 2012, the Corporation recorded E&P asset impairment charges totaling $582 million ($344 million after income taxes). These impairment charges consisted of $374 million ($228 million after income taxes) associated with the divestiture of assets in the Eagle Ford Shale in Texas and $208 million ($116 million after income taxes) related to non-producing properties in the UK North Sea. During 2011, the Corporation recorded E&P asset impairment charges of $358 million ($140 million after income taxes) related to non-producing properties.
10. HOVENSA L.L.C. Joint Venture
Hess Oil Virgin Islands Corp., 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. In 2013, 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. If an agreement to sell the refinery cannot be reached, HOVENSA will likely not be able to continue operating as an oil storage terminal.
In 2011 the Corporation recorded a total of $1,073 million of losses from its equity investment in HOVENSA, which included $875 million ($525 million after income taxes) related to an impairment recorded by HOVENSA and other charges associated with its decision to shut down the refinery. The Corporation’s share of the impairment related losses recorded by HOVENSA represented an amount equivalent to the Corporation’s financial support to HOVENSA at December 31, 2011, its planned future funding commitments for costs related to the refinery shutdown, and a charge of $135 million for the write-off of related assets held by the subsidiary which owns the Corporation’s investment in HOVENSA.
The Corporation’s investment in HOVENSA is accounted for using the equity method. In accordance with Rule 3-09 of Regulation S-X, the Corporation has filed financial statements for HOVENSA in this report on Form 10-K.
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11. Asset Retirement Obligations
The following table describes changes to the Corporation’s asset retirement obligations:
The revisions in 2013 and 2012 reflect overall increases in estimated abandonment obligations resulting from changes in the expected scope of operations, increases in the time expected to complete dismantlement activities and updates to service rates.
12. Debt and Interest Expense
Long-term debt at December 31 consisted of the following:
The Corporation has a $4 billion syndicated revolving credit facility that is unused at December 31, 2013 and matures in April 2016. This facility can be used for borrowings and letters of credit. Borrowings on the facility bear interest at 1.25% above the London Interbank Offered Rate. A fee of 0.25% per annum is also payable on the amount of the facility. The interest rate and facility fee are subject to adjustment if the Corporation’s credit rating changes. The Corporation also had a 364-day asset-backed credit facility which was terminated in September 2013.
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During 2013, the Corporation repaid a net amount of $2,348 million under available credit facilities, which consisted of $758 million from its syndicated revolving credit facility, $990 million from the Corporation’s short-term credit facilities and $600 million from its asset-backed credit facility. The Corporation recorded capital lease obligations totaling $98 million in conjunction with its commitment to acquire 50 existing Hess retail gasoline stations that were previously held under operating leases. The Corporation repaid $136 million of other debt in 2013.
At December 31, 2013, the Corporation’s fixed-rate public notes have a principal amount of $5,300 million ($5,275 million net of unamortized discount). Interest rates on the outstanding fixed-rate public notes have a weighted average rate of 6.9%.
During 2013, the Corporation recorded a net increase of $116 million in debt related to progress on construction of a leased floating production system to be used at the Tubular Bells project.
The aggregate long-term debt maturing during the next five years is as follows (in millions): 2014 - $378; 2015 - $74; 2016 - $78; 2017 - $89 and 2018 - $58.
The Corporation’s long-term debt agreements, including the revolving credit facility, contain financial covenants that restrict the amount of total borrowings and secured debt. At December 31, 2013, the Corporation is permitted to borrow up to an additional $35.5 billion for the construction or acquisition of assets. The Corporation has the ability to borrow up to an additional $5.9 billion of secured debt at December 31, 2013.
Outstanding letters of credit at December 31 were as follows:
* Committed and uncommitted lines have expiration dates through 2015.
Of the $410 million of letters of credit outstanding at December 31, 2013, $117 million relates to contingent liabilities and the remaining $293 million relates to liabilities recorded in the Consolidated Balance Sheet.
The total amount of interest paid (net of amounts capitalized) was $408 million, $419 million and $383 million in 2013, 2012 and 2011, respectively. The Corporation capitalized interest of $60 million, $28 million and $13 million in 2013, 2012 and 2011, respectively.
13. Share-based Compensation
The Corporation granted restricted common shares and performance share units (PSUs) in 2013 and 2012 under its 2008 Long-term Incentive Plan (LTIP), as amended. The Corporation began awarding PSUs under this plan in March 2012. Prior to 2012, the Corporation awarded restricted common stock and stock options. Outstanding restricted stock and PSUs generally vest three years from the date of grant. Outstanding stock options vest over three years from the date of grant and have a 10-year term and an exercise price equal to the market price on the date of grant.
The number of shares of common stock to be issued under the PSU agreement is based on a comparison of the Corporation’s total shareholder return (TSR) to the TSR of a predetermined group of fifteen peer companies over a three-year performance period ending December 31 of the year prior to grant issuance. Payouts of the performance share awards will range from 0% to 200% of the target awards based on the Corporation’s TSR ranking within the peer group. Dividend equivalents for the performance period will accrue on performance shares, but will only be paid out on earned shares after the performance period.
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Share-based compensation expense consisted of the following:
* Includes pre-tax share-based compensation expense (benefit) included in Income from discontinued operations of approximately $(6) million, $16 million and $18 million for 2013, 2012 and 2011, respectively.
During 2013, the Corporation reversed share-based compensation expenses totaling $33 million ($25 million for restricted stock, $7 million for PSUs and $1 million for stock options) for grants that are not expected to vest as a result of the Corporation’s transformation to a pure play E&P company.
Based on share-based compensation awards outstanding at December 31, 2013, unearned compensation expense, before income taxes, will be recognized in future years as follows (in millions): 2014 - $45, 2015 - $27 and 2016 - $4.
The Corporation’s share-based compensation activity consisted of the following:
* Includes 9,570 thousand exercisable options at a weighted average price of $61.99 at December 31, 2013.
The table below summarizes information regarding the outstanding and exercisable stock options as of December 31, 2013:
The intrinsic value (or the amount by which the market price of the Corporation’s common stock exceeds the exercise price of an option) at December 31, 2013 totaled $204 million and $203 million for outstanding options and exercisable
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options, respectively. At December 31, 2013, the weighted average remaining contractual term of exercisable options was four years.
The following weighted average assumptions were utilized to estimate the fair value of PSU awards:
The risk free interest rate is based on the vesting period of the award and is obtained from published sources. The stock price volatility is determined from the historical stock prices of the peer group using the vesting period. The contractual term is equivalent to the vesting period.
In May 2008, shareholders approved the 2008 LTIP, which was amended in May 2010 and May 2012 to increase the number of new shares of common stock available for awards. At December 31, 2013, the Corporation had 10.2 million shares that remain available for issuance under the 2008 LTIP, as amended, out of the total of 29 million shares of common stock authorized for issuance under the 2008 LTIP, as amended.
14. Foreign Currency
Foreign currency gains (losses) before income taxes recorded in Other, net in the Statement of Consolidated Income amounted to a loss of $54 million in 2013, a gain of $37 million in 2012 and a loss of $29 million in 2011, all of which related to the Corporation’s continuing operations. The after-tax foreign currency translation adjustments included in Accumulated other comprehensive income (loss) totaled $(1) million at December 31, 2013 and $169 million at December 31, 2012.
15. Retirement Plans
The Corporation has funded noncontributory defined benefit pension plans for a significant portion of its employees. In addition, the Corporation has an unfunded supplemental pension plan covering certain employees, which provides incremental payments that would have been payable from the Corporation’s principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average salary. Additionally, the Corporation maintains an unfunded postretirement medical plan that provides health benefits to certain qualified retirees from ages 55 through 65. The measurement date for all retirement plans is December 31.
The following table summarizes the Corporation’s benefit obligations and the fair value of plan assets and shows the funded status of the pension and postretirement medical plans:
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(a) During the first quarter of 2013, the Corporation’s pension and other postretirement plans were impacted by a significant reduction in the expected future service from active participants due to the Corporation’s announced asset sales program.
(b) Plan settlements amounts reported include a charge of $9 million ($5 million after income taxes) due to employee retirements in 2012.
Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following:
* The after-tax deficit reflected in Accumulated other comprehensive income (loss) for these retirement plans was $342 million at December 31, 2013 and $639 million at December 31, 2012.
The accumulated benefit obligation for the funded defined benefit pension plans decreased to $1,873 million at December 31, 2013 from $1,937 million at December 31, 2012. The accumulated benefit obligation for the unfunded defined benefit pension plan was $222 million at December 31, 2013 and $216 million at December 31, 2012.
Components of net periodic benefit cost for funded and unfunded pension plans and the postretirement medical plan consisted of the following:
The Corporation’s 2014 pension and postretirement medical expense is estimated to be approximately $20 million, which includes approximately $28 million related to the amortization of unrecognized net actuarial losses, offset by improved returns on plan assets.
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The weighted average actuarial assumptions used by the Corporation’s funded and unfunded pension plans were as follows:
The actuarial assumptions used by the Corporation’s postretirement medical plan were as follows:
The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year while the assumptions used to determine benefit obligations were established at each year-end. The net periodic benefit cost and the actuarial present value of benefit obligations are based on actuarial assumptions that are reviewed on an annual basis. The discount rate is developed based on a portfolio of high-quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations. The overall expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category.
The Corporation’s investment strategy is to maximize long-term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by the Corporation’s investment committee and include domestic and foreign equities, fixed income, and other investments, including hedge funds, real estate and private equity. Investment managers are prohibited from investing in securities issued by the Corporation unless indirectly held as part of an index strategy. The majority of plan assets are highly liquid, providing ample liquidity for benefit payment requirements. The current target allocations for plan assets are 50% equity securities, 25% fixed income securities (including cash and short-term investment funds) and 25% to all other types of investments. Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels.
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The following tables provide the fair value of the financial assets of the funded pension plans as of December 31, 2013 and 2012 in accordance with the fair value measurement hierarchy described in Note 1, Summary of Significant Accounting Policies in the notes to the Consolidated Financial Statements:
(a) Includes securities issued and guaranteed by U.S. and non-U.S. governments.
(b) Primarily consists of securities issued by governmental agencies and municipalities.
(c) Comprised of U.S. residential and commercial mortgage-backed securities.
Cash and short-term investment funds consist of cash on hand and short-term investment funds that provide for daily investments and redemptions and are valued and carried at a $1 net asset value (NAV) per fund share. Cash on hand is classified as Level 1 and short-term investment funds are classified as Level 2.
Equities consist of equity securities issued by U.S. and non-U.S. corporations as well as commingled investment funds that invest in equity securities. Individually held equity securities, which are traded actively on exchanges and have readily available price quotes, are classified as Level 1. Commingled fund values, which are valued at the NAV per fund share derived from the quoted prices in active markets of the underlying securities, are classified as Level 2.
Fixed income investments consist of securities issued by the U.S. government, non-U.S. governments, governmental agencies, municipalities and corporations, and agency and non-agency mortgage-backed securities. This investment category
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also includes commingled investment funds that invest in fixed income securities. Individual fixed income securities are generally priced on the basis of evaluated prices from independent pricing services, which are monitored and provided by the third-party custodial firm responsible for safekeeping plan assets. Individual fixed income securities are classified as Level 2 or 3. Fixed income commingled fund values, which reflect the NAV per fund share derived indirectly from observable inputs or from quoted prices in less liquid markets of the underlying securities, are classified as Level 2.
Other investments consist of exchange-traded real estate investment trust securities, as well as commingled fund and limited partnership investments in hedge funds, private equity, real estate and diversified commodities. Exchange-traded securities are classified as Level 1. Commingled fund values reflect the NAV per fund share and are classified as Level 2 or 3. Private equity and real estate limited partnership values reflect information reported by the fund managers, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data and independent appraisals from third-party sources with professional qualifications. Hedge funds, private equity and non-exchange-traded real estate investments are classified as Level 3.
The following tables provide changes in financial assets that are measured at fair value based on Level 3 inputs that are held by institutional funds classified as:
* Fixed Income includes treasury and government issued, government related, mortgage-backed and corporate securities.
The Corporation has budgeted contributions of approximately $80 million to its funded pension plans in 2014.
Estimated future benefit payments by the funded and unfunded pension plans and the postretirement medical plan, which reflect expected future service, are as follows (in millions):
The Corporation also contributes to several defined contribution plans for eligible employees. Employees may contribute a portion of their compensation to the plans and the Corporation matches a portion of the employee contributions. The Corporation recorded expense of $41 million in 2013, $40 million in 2012 and $28 million in 2011 for contributions to these plans.
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16. Income Taxes
The provision (benefit) for income taxes from continuing operations consisted of:
* In 2013, amount reflects $674 million for the effect of the Denmark hydrocarbon income tax law change to the Chapter 3A regime from the Chapter 3 regime in December 2013 and $8 million for the effect of a change in Norway’s hydrocarbon and base corporate income tax rates in December 2013. In 2012, amount reflects the effect of the UK supplementary income tax rate change in July 2012. In 2011, amount reflects the July 2011 increase in the supplementary tax on petroleum operations in the UK.
Income from continuing operations before income taxes consisted of the following:
(a) Includes substantially all of the Corporation’s interest expense and the results of hedging activities.
(b) Foreign income includes the Corporation’s Virgin Islands and other operations located outside of the U.S.
The components of deferred tax liabilities and deferred tax assets at December 31 were as follows:
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At December 31, 2013, the Corporation has recognized a gross deferred tax asset related to net operating loss carryforwards of $2,726 million before application of the valuation allowances. The deferred tax asset is comprised of $2,390 million attributable to foreign net operating losses which begin to expire in 2020, $71 million attributable to U.S. federal operating losses which begin to expire in 2020 and $265 million attributable to losses in various U.S. states which begin to expire in 2014. The deferred tax asset attributable to foreign net operating losses, net of valuation allowances, is $1,704 million, substantially all of which relates to loss carryforwards in Denmark, Norway and Malaysia. At December 31, 2013, the Corporation has federal, state and foreign alternative minimum tax credit carryforwards of $110 million which can be carried forward indefinitely, and approximately $1 million of other business credit carryforwards. Foreign tax credit carryforwards, which begin to expire in 2016, total $50 million.
In the Consolidated Balance Sheet, deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at December 31 as follows:
A net deferred tax liability of $157 million, primarily relating to fixed asset basis differences and net operating losses of the Corporation’s subsidiaries in Thailand and Indonesia, is included in current liabilities associated with assets held for sale in the Consolidated Balance Sheet at December 31, 2013.
The difference between the Corporation’s effective income tax rate from continuing operations and the U.S. statutory rate is reconciled below:
* The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the suspension of operations in Libya for most of 2011 and part of 2013.
Below is a reconciliation of the beginning and ending amounts of unrecognized tax benefits:
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The December 31, 2013 balance of unrecognized tax benefits includes $503 million that, if recognized, would impact the Corporation’s effective income tax rate. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by $15 million to $25 million due to settlements with taxing authorities or other resolutions, as well as lapses in statutes of limitation. The Corporation had accrued interest and penalties related to unrecognized tax benefits of $52 million and $60 million as of December 31, 2013 and 2012, respectively.
The Corporation has not recognized deferred income taxes on the portion of undistributed earnings of foreign subsidiaries expected to be indefinitely reinvested in foreign operations. The Corporation had undistributed earnings from foreign subsidiaries that it expects to be indefinitely reinvested in foreign operations of approximately $7.5 billion as of December 31, 2013. If these earnings were not indefinitely reinvested, a deferred tax liability of approximately $2.6 billion would be recognized, not accounting for the utilization of foreign tax credits in the U.S.
The Corporation and its subsidiaries file income tax returns in the U.S. and various foreign jurisdictions. The Corporation is no longer subject to examinations by income tax authorities in most jurisdictions for years prior to 2005.
Income taxes paid (net of refunds) in 2013, 2012 and 2011 amounted to $1,353 million, $1,822 million and $1,384 million, respectively.
17. Outstanding and Weighted Average Common Shares
The following table provides the changes in the Corporation’s outstanding common shares:
* See Note 18, Share Repurchase Plan in the notes to the Consolidated Financial Statements.
The following table presents the calculation of basic and diluted earnings per share:
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The weighted average common shares used in the diluted earnings per share calculations exclude the effect of approximately 4.4 million, 9.2 million and 3.5 million out-of-the-money stock options for 2013, 2012 and 2011, respectively. Based on the Corporation’s TSR, the diluted earnings per share calculations also exclude the effects of 414,175 PSUs for 2012. 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) during 2013. Cash dividends were $0.40 per share ($0.10 per quarter) for both 2012 and 2011.
18. Share Repurchase Plan
In March 2013, the Corporation announced a board authorized plan to repurchase up to $4 billion of outstanding common stock using proceeds from its announced asset divestiture program. From August through December 31, 2013, the Corporation purchased approximately 19.3 million shares for a total cost of approximately $1.54 billion, which is an average cost of $79.65 per share including transaction fees. As of December 31, 2013, the Corporation may purchase up to approximately $2.46 billion of additional common stock under its board authorized plan. The weighted average of common shares outstanding used in the earnings per share calculations for 2013 do not reflect the full amount of the stock repurchases, due to the timing of the purchases.
19. Leased Assets
The Corporation and certain of its subsidiaries lease gasoline stations, drilling rigs, tankers, office space and other assets for varying periods under contractual obligations accounted for as operating leases. Certain operating leases provide an option to purchase the related property at fixed prices. At December 31, 2013, future minimum rental payments applicable to non-cancelable operating leases with remaining terms of one year or more (other than oil and gas property leases) are as follows (in millions):
Operating lease expenses for drilling rigs used to drill development wells and successful exploration wells are capitalized.
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Rental expense was as follows:
20. Guarantees and Contingencies
At December 31, 2013, the Corporation has $117 million in letters of credit for which it is contingently liable. The Corporation is subject to loss contingencies with respect to various lawsuits, claims and other proceedings, including environmental matters. A liability is recognized in the Corporation’s consolidated financial statements when it is probable a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, the Corporation discloses the nature of those contingencies.
The Corporation, along with many other companies engaged in refining and marketing of gasoline, has been a party to lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline. A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the United States against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including the Corporation. The principal allegation in all cases was that gasoline containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. In 2008, the majority of the cases against the Corporation were settled. In 2010 and 2011, additional cases were settled including an action brought in state court by the State of New Hampshire. Cases brought by the State of New Jersey and the Commonwealth of Puerto Rico remain unresolved. The Corporation has reserves recorded which it believes are adequate to cover its expected liability in these cases.
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.
21. Segment Information
The Corporation is transitioning to a pure play E&P company. In the first quarter of 2013, the Corporation announced plans to divest its downstream businesses, which were previously included in the M&R operating segment. Accordingly, the results of operations for the downstream businesses that were sold or ceased operations during 2013 have been classified as discontinued operations and are excluded from these segment disclosures for all periods presented. As a result, the Corporation currently has two operating segments, E&P and Retail Marketing and Other, which consists of the remaining downstream businesses that it plans to divest. This structure is used by the chief operating decision maker to allocate resources and assess operating performance.
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The following table presents financial data by operating segment:
(a) Consists of Sales and other operating revenues that are reported net of excise and similar taxes in the Statement of Consolidated Income, which amounted to approximately $1,230 million, $1,530 million and $1,450 million in 2013, 2012 and 2011, respectively.
(b) Excludes identifiable assets related to the discontinued operations.
(c) E&P, Retail Marketing and Other and Corporate only. Calculated as equity plus debt.
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The following table presents financial information by major geographic area:
(a) Of the total Europe, Property, plant and equipment (net), Norway represented $6,348 million, $6,426 million and $5,031 million in 2013, 2012 and 2011, respectively.
(b) Excludes Property, plant and equipment (net) related to the discontinued operations.
22. Related Party Transactions
The following table presents the Corporation’s related party transactions:
(a) The Corporation ceased purchasing refined products from HOVENSA following the closure of HOVENSA’s refinery in January 2012.
(b) Represents purchases of electricity from this 50% owned joint venture under a tolling agreement.
The following table presents the Corporation’s related party accounts receivable (payable) at December 31:
23. Risk Management and Trading Activities
In the normal course of its business, the Corporation is exposed to commodity risks related to changes in the prices of crude oil, natural gas, refined petroleum products and electricity, as well as changes in interest rates and foreign currency values. In the disclosures that follow, risk management activities are referred to as corporate and energy marketing risk management activities. The Corporation also has trading operations, through a 50% voting interest in a consolidated partnership, that trades energy-related commodities, securities and derivatives. These activities are also exposed to commodity price risks primarily related to the prices of crude oil, natural gas, refined petroleum products and electricity as well as foreign currency values. In March 2013, the Corporation announced plans to divest its downstream businesses, which included its energy marketing risk management and trading activities. In November, the Corporation completed the sale of its energy marketing business.
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The Corporation maintains a control environment for all of its risk management and trading activities under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include volumetric, term and value at risk limits. The chief risk officer must approve the trading of new instruments and commodities. Risk limits are monitored and reported on a daily basis to business units and senior management. The Corporation’s risk management department also performs independent price verifications (IPV’s) of sources of fair values and validations of valuation models. The Corporation’s treasury department is responsible for administering foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable.
The Corporation’s risk management department, in performing the IPV procedures, utilizes independent sources and valuation models that are specific to the individual contracts and pricing locations to identify positions that require adjustments to better reflect the market. This review is performed quarterly and the results are presented to the chief risk officer and senior management. The IPV process considers the reliability of the pricing services through assessing the number of available quotes, the frequency at which data is available and, where appropriate, the comparability between pricing sources.
Following is a description of the Corporation’s activities that use derivatives as part of their operations and strategies. Derivatives include both financial instruments and forward purchase and sale contracts. Gross notional amounts of both long and short positions are presented in the volume tables beginning below. These amounts include long and short positions that offset in closed positions and have not reached contractual maturity. Gross notional amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash settlements under the contracts.
Corporate Risk Management Activities: Corporate risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas produced by the Corporation or to reduce exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price of a portion of the Corporation’s crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which the Corporation does business with the intent of reducing exposure to foreign currency fluctuations. These forward contracts comprise various currencies including the British Pound and Thai Baht. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.
The gross volumes of the Corporate risk management derivative contracts outstanding at December 31, were as follows:
Crude oil price hedging contracts increased E&P Sales and other operating revenues by $39 million ($25 million after income taxes) in 2013, and reduced E&P Sales and other operating revenues by $688 million ($431 million after income taxes) in 2012 and $517 million ($327 million after income taxes) in 2011. At December 31, 2013, the after-tax deferred gains in Accumulated other comprehensive income (loss) related to Brent crude oil hedges were $5 million, which will be reclassified into earnings during 2014 as the hedged crude oil sales are recognized in earnings. The amount of ineffectiveness from Brent crude oil hedges that was recognized immediately in Sales and other operating revenues was immaterial in 2013, a loss of $9 million in 2012 and a gain of $9 million in 2011.
During 2013, the Corporation had Brent crude oil fixed-price swap contracts to hedge 90,000 barrels of oil per day (bopd) of crude oil sales volumes at an average price of approximately $109.70 per barrel. In October 2008, the Corporation closed Brent crude oil hedges covering 24,000 bopd through 2012 by entering into offsetting contracts with the same counterparty. The deferred after-tax losses, as of the date the hedge positions were closed, were recorded in earnings as the contracts matured. The Corporation also had Brent crude oil fixed-price swap contracts to hedge 120,000 bopd of crude oil sales volumes for the full year of 2012 at an average price of $107.70 per barrel. The Corporation has entered into Brent crude oil fixed price swap contracts to hedge 25,000 bopd for calendar year 2014 at an average price of $109.12 per barrel.
At December 31, 2013 and 2012, the Corporation had interest rate swaps with gross notional amounts of $865 million and $880 million, respectively, which were designated as fair value hedges. Changes in the fair value of interest rate swaps and the hedged fixed-rate debt are recorded in Interest expense in the Statement of Consolidated Income. For the years ended December 31, 2013 and 2012, the Corporation recorded a decrease of $35 million and an increase of $12 million (excluding
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
accrued interest) respectively, in the fair value of interest rate swaps and a corresponding adjustment in the carrying value of the hedged fixed-rate debt.
Gains or losses on foreign exchange contracts that are not designated as hedges are recognized immediately in Other, net in Revenues and non-operating income in the Statement of Consolidated Income.
Net realized and unrealized pre-tax gains (losses) on derivative contracts used in Corporate Risk Management activities and not designated as hedges amounted to the following:
Energy Marketing Risk Management Activities: In November 2013, the Corporation completed the sale of its energy marketing business to Direct Energy, a North American subsidiary of Centrica plc (Centrica). Certain derivative contracts, including new transactions following the closing date, (the “delayed transfer derivative contracts”) have not been transferred to Direct Energy, as required customer or regulatory consents have not been obtained. However, the agreement entered into between Hess and Direct Energy on the closing date transfers all economic risks and rewards of the energy marketing business, including the ownership of the delayed transfer derivative contracts, to Direct Energy. As a result, the assets and liabilities related to the delayed transfer derivative contracts remain on the Corporation’s Consolidated Balance Sheet at December 31, 2013 but changes in their fair value are offset based on the terms of the agreement between Hess and Direct Energy. The Corporation therefore has no market risk related to these delayed transfer derivative contracts and only retains credit risk exposure, which has been guaranteed by Centrica. It is expected that the transfer of these contracts will be substantially complete in the first half of 2014.
The gross volumes of the Corporation’s energy marketing derivative contracts outstanding at December 31, including the delayed derivative transfer contracts were as follows:
* One mcf represents one thousand cubic feet.
The changes in fair value of certain energy marketing commodity contracts that are not designated as hedges, as well as revenues from the sales contracts, supply contract purchases and net settlements from financial derivatives related to these energy marketing activities, are presented in Income from discontinued operations in the Statement of Consolidated Income. For contracts that were designated as hedges, the effective portion of changes in the fair value of cash flow hedges was recorded as a component of Accumulated other comprehensive income (loss) in the Consolidated Balance Sheet. Net realized and unrealized pre-tax gains on derivative contracts not designated as hedges amounted to $22 million in 2013, $127 million in 2012 and $65 million in 2011. After-tax deferred losses relating to energy marketing activities recorded in Accumulated other comprehensive income (loss) were $22 million at December 31, 2012, all of which were re-classified into Income from discontinued operations during the year. There were no after-tax deferred gains or losses relating to energy marketing activities recorded in Accumulated other comprehensive income (loss) at December 31, 2013.
Trading Activities: Trading activities are conducted through a trading partnership in which the Corporation has a 50% voting interest that is currently for sale. This partnership intends to generate earnings through various strategies primarily using energy-related commodities, securities and derivatives. The information that follows represents 100% of the trading partnership and, for 2012, the Corporation’s proprietary trading accounts.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The gross volumes of derivative contracts outstanding related to trading activities at December 31, were as follows:
Pre-tax unrealized and realized gains (losses) recorded in the Statement of Consolidated Income from trading activities amounted to the following:
* The unrealized pre-tax gains and losses included in earnings were reflected in Sales and other operating revenues and Income from discontinued operations in the Statement of Consolidated Income.
Fair Value Measurements: The Corporation generally enters into master netting arrangements to mitigate legal and counterparty credit risk. Master netting arrangements are generally accepted overarching master contracts that govern all individual transactions with the same counterparty entity as a single legally enforceable agreement. The U.S. Bankruptcy Code provides for the enforcement of certain termination and netting rights under certain types of contracts upon the bankruptcy filing of a counterparty, commonly known as the “safe harbor” provisions. If a master netting arrangement provides for termination and netting upon the counterparty’s bankruptcy, these rights are generally enforceable with respect to “safe harbor” transactions. If these arrangements provide the right of offset and the Corporation’s intent and practice is to offset amounts in the case of such a termination, the Corporation’s policy is to record the fair value of derivative assets and liabilities on a net basis.
In the normal course of business the Corporation relies on legal and credit risk mitigation clauses providing for adequate credit assurance as well as close-out netting, including two-party netting and single counterparty multilateral netting. As applied to the Corporation, “two-party netting” is the right to net amounts owing under safe harbor transactions between a single defaulting counterparty entity and a single Hess entity, and “single counterparty multilateral netting” is the right to net amounts owing under safe harbor transactions among a single defaulting counterparty entity and multiple Hess entities. The Corporation is reasonably assured that these netting rights would be upheld in a bankruptcy proceeding in the U.S. in which the defaulting counterparty is a debtor under the U.S. Bankruptcy Code.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table provides information about the effect of netting arrangements on the presentation of the Corporation’s physical and financial derivative assets and (liabilities) that are measured at fair value, with the effect of single counterparty multilateral netting being included in column (v):
* There is no cash collateral that was not offset in the Consolidated Balance Sheet.
The net assets and liabilities that were offset in the Consolidated Balance Sheet as reflected in column (iv) of the table above were included in Accounts receivable - Trade and Accounts payable, respectively. Included in those amounts were the assets and liabilities related to the Corporation’s discontinued operations of $612 million and $620 million as of December 31, 2013, respectively ($378 million and $376 million as of December 31, 2012).
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The table below reflects the gross and net fair values of the corporate and energy marketing risk management and trading derivative instruments:
* Includes trading derivatives and derivatives used for risk management.
The Corporation determines fair value in accordance with the fair value measurements accounting standard (Accounting Standards Codification 820 - Fair Value Measurements and Disclosures), which established a hierarchy that categorizes the sources of inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2.
When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. To value derivatives that are characterized as Level 2 and 3, the Corporation uses observable inputs for similar instruments that are available from exchanges, pricing services or broker quotes. These observable inputs may be supplemented with other methods, including internal extrapolation or interpolation, that result in the most representative prices for instruments with similar characteristics. Multiple inputs may be used to measure fair value, however, the level of fair value for each physical derivative and financial asset or liability presented below is based on the lowest significant input level within this fair value hierarchy.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table provides the Corporation’s net physical derivative and financial assets and (liabilities) that are measured at fair value based on this hierarchy:
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(a) Includes a total of $239 million of Level 1, $180 million of Level 2 and $51 million of Level 3 assets that relate to the Corporation’s continuing operations.
(b) Includes a total of $79 million of Level 1, $447 million of Level 2 and $32 million of Level 3 liabilities that relate to the Corporation’s continuing operations.
(c) Long-term debt, including current maturities, had a carrying value of $5,798 million and $7,361 million at December 31, 2013 and 2012, respectively.
In addition to the financial assets and (liabilities) disclosed in the tables above, the Corporation had other short-term financial instruments, primarily cash equivalents and accounts receivable and payable, for which the carrying value approximated their fair value at December 31, 2013 and 2012.
The following table provides total net transfers into and out of each level of the fair value hierarchy:
The Corporation’s policy is to recognize transfers in and transfers out as of the end of the reporting period. Transfers between levels result from the passage of time as contracts move closer to their maturities, fluctuations in the market liquidity for certain contracts and/or changes in the level of significance of fair value measurement inputs.
The following table provides changes in physical derivatives and financial assets and (liabilities) that are measured at fair value based on Level 3 inputs:
(a) The unrealized pre-tax gains and losses included in earnings were reflected in Sales and other operating revenues and Income from discontinued operations in the Statement of Consolidated Income.
(b) The unrealized pre-tax gains (losses) included in the other comprehensive income (loss) are reflected in the Change in fair value of cash flow hedges in the Statement of Consolidated Comprehensive Income.
(c) Purchases and sales primarily represent option premiums paid or received, respectively, during the reporting period and were reflected in Sales and other operating revenues and Income from discontinued operations in the Statement of Consolidated Income.
(d) Settlements represent realized gains (losses) on derivatives settled during the reporting period and were reflected in Sales and other operating revenues and Income from discontinued operations in the Statement of Consolidated Income.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The significant unobservable inputs used in Level 3 fair value measurements for the Corporation’s physical commodity contracts and derivative instruments primarily include less liquid delivered locations for physical commodity contracts or volatility assumptions for out-of-the-money options. The following table provides information about the Corporation’s significant recurring unobservable inputs used in the Level 3 fair value measurements. Natural gas contracts are usually quoted and transacted using basis pricing relative to an active pricing location (e.g., Henry Hub), for which price inputs represent the approximate value of differences in geography and local market conditions. All other price inputs in the table beginning below represent full contract prices. Significant changes in any of the inputs, independently or correlated, may result in a different fair value.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(a) Price per barrel.
(b) Price per megawatt hour.
(c) Price per million British thermal unit.
Note: Fair value measurement for all recurring inputs was performed using a combination of income and market approach techniques.
Credit Risk: The Corporation is exposed to credit risks that may at times be concentrated with certain counterparties, groups of counterparties or customers. Accounts receivable are generated from a diverse domestic and international customer base. As of December 31, 2013, the Corporation’s net Accounts receivable - Trade related to continuing operations were concentrated with the following counterparty industry segments: Integrated Oil Companies - 45%, Refiners - 18%, Financial Institutions - 14%, Government Entities - 8% and Trading Companies - 7%. As of December 31, 2012, the Corporation’s net Accounts receivable - Trade, which included the receivables for the downstream businesses, were concentrated as follows: Integrated Oil Companies - 23%, Refiners - 15%, Government Entities - 11%, Real Estate - 8%, Services - 8% and Manufacturing - 6%. The Corporation reduces its risk related to certain counterparties by using master netting arrangements and requiring collateral, generally cash or letters of credit. The Corporation records the cash collateral received or posted as an offset to the fair value of derivatives executed with the same counterparty. At December 31, 2013 and December 31, 2012, the Corporation held cash from counterparties of $79 million and $34 million, respectively. The Corporation posted cash to counterparties at December 31, 2013 and December 31, 2012, of $168 million and $5 million, respectively.
The Corporation had outstanding letters of credit totaling $410 million and $746 million at December 31, 2013 and December 31, 2012, respectively, primarily issued to satisfy margin requirements (approximately $196 million and $357 million related to discontinued operations at December 31, 2013 and December 31, 2012, respectively). Certain of the Corporation’s agreements also contain contingent collateral provisions that could require the Corporation to post additional collateral if the Corporation’s credit rating declines. As of December 31, 2013 and 2012, the net liability related to both realized and unrealized derivative contracts with contingent collateral provisions was $281 million and approximately $435 million, respectively. As of December 31, 2013, the cash collateral posted on those derivatives was $31 million and there was no cash collateral posted as of December 31, 2012. At December 31, 2013 and 2012, all three major credit rating agencies that rate the Corporation’s debt had assigned an investment grade rating. If one of the three agencies were to
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
downgrade the Corporation’s rating below investment grade, the Corporation would be required to post additional collateral of $134 million at December 31, 2013 and approximately $275 million at December 31, 2012.
24. Subsequent Events
In January 2014, the Corporation completed the sale of its interest in the Pangkah asset, offshore Indonesia for cash proceeds of approximately $650 million. In January, the Corporation also announced that it had reached agreement to sell approximately 74,000 acres of its dry gas position in the Utica Shale for $924 million. Approximately two-thirds of these proceeds are expected at the end of the first quarter of 2014, with the balance to be received in the third quarter of 2014.
In January 2014, the Corporation’s retail marketing business acquired its partner’s 56% interest in WilcoHess, a retail gasoline joint venture, for approximately $290 million and the settlement of liabilities.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
The Supplementary Oil and Gas Data that follows is presented in accordance with ASC 932, Disclosures about Oil and Gas Producing Activities, and includes (1) costs incurred, capitalized costs and results of operations relating to oil and gas producing activities, (2) net proved oil and gas reserves and (3) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves, including a reconciliation of changes therein.
During the three year period which ended December 31, 2013, the Corporation produced crude oil, natural gas liquids and/or natural gas principally in the United States (U.S.), Europe (Norway, Denmark, Russia and the United Kingdom), Africa (Equatorial Guinea, Libya and Algeria) and Asia and Other (Malaysia, Thailand, Azerbaijan and Indonesia). Exploration activities were also conducted, or are planned, in certain of these areas as well as additional countries.
Costs Incurred in Oil and Gas Producing Activities
(a) Includes $560 million, $319 million and $432 million of exploration costs incurred for unconventional assets in 2013, 2012 and 2011, respectively.
(b) Includes $615 million, $715 million and $972 million in 2013, 2012 and 2011, respectively, related to the accruals and revisions for asset retirement obligations.
(c) Costs incurred in oil and gas producing activities in Norway, were as follows for the years ended December 31:
* Includes accruals and revisions for asset retirement obligations.
Capitalized Costs Relating to Oil and Gas Producing Activities
Results of Operations for Oil and Gas Producing Activities
The results of operations shown below exclude non-oil and gas producing activities, primarily gains on sales of oil and gas properties, sales of purchased crude oil and natural gas, interest expense, gains and losses resulting from foreign exchange transactions and other non-operating income. Therefore, these results are on a different basis than the net income from E&P operations reported in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 21, Segment Information in the notes to the Consolidated Financial Statements.
(a) Results of operations for oil and gas producing activities in Norway were as follows for the years ended December 31:
(b) Excludes a deferred tax benefit of $674 million which represents the effect of the Denmark hydrocarbon income tax law change to the Chapter 3A regime from the Chapter 3 regime in December 2013.
(c) Asia and Other excludes an income tax charge of $86 million for a disputed application of an international tax treaty.
Oil and Gas Reserves
The Corporation’s proved oil and gas reserves are calculated in accordance with the Securities and Exchange Commission (SEC) regulations and the requirements of the Financial Accounting Standards Board. Proved oil and gas reserves are quantities, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. The Corporation’s estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed by internal teams of geoscience professionals and reservoir engineers. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir is based on the maturity of the reservoir, the completeness of the subsurface data available at the time of the estimate, the stage of reservoir development and the production history. Where applicable, reliable technologies may be used in reserve estimation, as defined in the SEC regulations. These technologies, including computational methods, must have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In order for reserves to be classified as proved, any required government approvals must be obtained and depending on the cost of the project, either senior management or the Board of Directors must commit to fund the development. The Corporation’s proved reserves are subject to certain risks and uncertainties, which are discussed in Item 1A, Risk Factors Related to Our Business and Operations of this Form 10-K.
Internal Controls
The Corporation maintains internal controls over its oil and gas reserve estimation process which are administered by the Corporation’s Vice President of E&P Technology and its Chief Financial Officer. Estimates of reserves are prepared by technical staff that work directly with the oil and gas properties using standard reserve estimation guidelines, definitions and methodologies. Each year, reserve estimates for a selection of the Corporation’s assets are subject to internal technical audits and reviews. In addition, an independent third party reserve engineer reviews and audits a significant portion of the Corporation’s reported reserves (see pages 90 through 91). Reserve estimates are reviewed by senior management and the Board of directors.
Qualifications
The person primarily responsible for overseeing the preparation of the Corporation’s oil and gas reserves during 2013 was Mr. Randy Johnson, Vice President of E&P Technology. Mr. Johnson is a member of the Society of Petroleum Engineers and has over 30 years of experience in the oil and gas industry with a BS degree in Engineering and a MS degree in Petroleum Engineering. He is a licensed professional engineer in Texas. His experience includes over 20 years primarily focused on oil and gas subsurface understanding and reserves estimation in both domestic and international areas. The Corporation’s upstream technology organization, which Mr. Johnson manages, focuses on oil and gas industry subsurface and reservoir engineering technologies and evaluation techniques. Mr. Johnson is also responsible for the Corporation’s
Global Reserves group, which is the internal organization responsible for establishing the policies and processes used within the operating units to estimate reserves and perform internal technical reserve audits and reviews.
Reserves Audit
The Corporation engaged the consulting firm of DeGolyer and MacNaughton (D&M) to perform an audit of the internally prepared reserve estimates on certain fields aggregating 82% of 2013 year-end reported reserve quantities on a barrel of oil equivalent basis (76% in 2012). The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates and compliance with SEC regulations. The D&M letter report, dated February 7, 2014, on the Corporation’s estimated oil and gas reserves was prepared using standard geological and engineering methods generally recognized in the petroleum industry. D&M is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. D&M’s letter report on the Corporation’s December 31, 2013 oil and gas reserves is included as an exhibit to this Form 10-K. While the D&M report should be read in its entirety, the report concludes that for the properties reviewed by D&M, the total net proved reserve estimates prepared by Hess and audited by D&M, in the aggregate, differed by approximately 2% of total audited net proved reserves on a barrel of oil equivalent basis. The report also includes among other information, the qualifications of the technical person primarily responsible for overseeing the reserve audit.
Following are the Corporation’s proved reserves:
(a) Includes the impact of changes in selling prices on the reserve estimates for production sharing contracts with cost recovery provisions. Revisions included an increase of 0.1 million barrels to crude oil, condensate and natural gas liquids reserves in 2013. Reductions to crude oil, condensate and natural gas liquids reserves were 2 million barrels and 11 million barrels in 2012 and 2011, respectively, due to higher selling prices. Revisions also included reductions to natural gas reserves of 9 million mcf, 2 million mcf and 83 million mcf in 2013, 2012 and 2011, respectively, due to higher selling prices.
(b) Includes 8 million barrels in 2012 and 10 million barrels in 2011 of crude oil reserves relating to a noncontrolling interest owner of a corporate joint venture. The corporate joint venture was sold in April 2013.
(c) Excludes approximately 270 million mcf of carbon dioxide gas for sale or use in company operations.
(d) Natural gas liquids net proved developed reserves were 61 million barrels, 76 million barrels and 56 million barrels at December 31, 2013, 2012 and 2011, respectively, and 54 million barrels at January 1, 2011. Natural gas liquids net proved developed reserves in the United States were 83%, 82% and 74% at December 31, 2013, 2012 and 2011, respectively. Natural gas liquids net proved developed reserves in Norway were 15%, 10% and 16% at December 31, 2013, 2012 and 2011, respectively.
(e) Natural gas liquids net proved undeveloped reserves were 75 million barrels, 60 million barrels and 57 million barrels at December 31, 2013, 2012 and 2011, respectively, and 48 million barrels at January 1, 2011. Natural gas liquids net proved undeveloped reserves in the United States were 83%, 72% and 67% at December 31, 2013, 2012 and 2011, respectively. Natural gas liquids net proved undeveloped reserves in Norway were 15%, 25% and 28% at December 31, 2013, 2012 and 2011, respectively.
(f) Natural gas production includes volumes used for fuel.
(g) Proved reserves in Norway were as follows:
(h) Natural gas reserves in Africa were 160 million mcf in 2013, 142 million mcf in 2012 and 71 million mcf in 2011.
Proved Undeveloped Reserves
The December 31, 2013 oil and gas reserve estimates disclosed above include 502 million barrels of liquid hydrocarbons and 865 million mcf of natural gas, or an aggregate of 646 million barrels of oil equivalent (boe), classified as proved undeveloped reserves. Overall volumes of proved undeveloped reserves decreased by 28 million boe compared with year-end 2012. Additions and revisions in proved undeveloped reserves from existing fields amounted to 123 million boe, primarily in the United States. These increases resulted from ongoing technical assessments, performance evaluations and additional planned development activities. In 2013, 88 million boe were converted from proved undeveloped reserves to proved developed reserves resulting from continuing development activity and new wells principally in North Dakota and the Gulf of Mexico in the U.S., Norway, Libya, Malaysia and Equatorial Guinea. The Corporation estimates that capital expenditures of $1,765 million were incurred to convert proved undeveloped reserves to proved developed reserves during 2013. Dispositions of assets in 2013 further reduced proved undeveloped reserves by 63 million boe.
The Corporation is involved in multiple long-term projects that have staged developments. Certain of these projects have proved reserves, which have been classified as undeveloped for a period in excess of five years, totaling 90 million boe or 6% of total 2013 proved reserves. Most of the proved undeveloped reserves in excess of five years relate to two offshore producing assets. As discussed below, a natural gas project at the JDA is being developed in phases to meet long-term natural gas sales contracts and an oil and gas project at the Valhall Field in Norway is also being developed in phases. A summary of the development status of each of the projects follows:
•
JDA - This natural gas project in the Gulf of Thailand currently has a central processing platform and nine wellhead platforms. In 2013, the operator continued development drilling, successfully installed two new wellhead platforms, sanctioned a further wellhead platform and continued a major booster compression project. In 2014, the operator intends to progress the compression project, continue development drilling and commence production at the platforms installed in 2013.
•
Valhall - The multi-year Valhall redevelopment project was completed in early 2013. The project included the installation of a new production, utilities and accommodation platform, and expansion of gross production capacity to 120,000 barrels of liquids per day and 143,000 mcf of natural gas per day. The operator plans a multi-year development drilling program.
Production Sharing Contracts
The Corporation’s proved reserves include crude oil and natural gas reserves relating to long-term agreements with governments or authorities in which the Corporation has the legal right to produce or has a revenue interest in the production. Proved reserves from these production sharing contracts for each of the three years ended December 31, 2013 are presented separately below, as well as volumes produced and received during 2013, 2012 and 2011 from these production sharing contracts.
* Includes natural gas liquids of 3 million barrels in 2013, 5 million barrels in 2012 and 5 million barrels in 2011.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Future net cash flows are calculated by applying prescribed oil and gas selling prices used in determining year-end reserve estimates (adjusted for price changes provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future development and production costs, which are based on year-end costs and existing economic assumptions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the pre-tax net cash flows relating to the Corporation’s proved oil and gas reserves. Future net cash flows are discounted at the prescribed rate of 10%. The discounted future net cash flow estimates do not include exploration expenses, interest expense or corporate general and administrative expenses. The selling prices of crude oil and natural gas are highly volatile. The prices which are required to be used for the discounted future net cash flows do not include the effects of hedges and may not be representative of future selling prices. The future net cash flow estimates could be materially different if other assumptions were used.
* At December 31, the standardized measure of discounted future net cash flows relating to proved reserves in Norway were as follows:
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
QUARTERLY FINANCIAL DATA (UNAUDITED)
Following are quarterly results of operations:
(a) Gross profit represents Sales and other operating revenues, less Cost of products sold, Operating costs and expenses, Production and severance taxes, Marketing expenses, Depreciation, depletion and amortization and Asset impairments.
(b) Includes after-tax gains of $820 million related to asset sales and the liquidation of LIFO inventories, partially offset by after-tax charges of $213 million for an asset impairment, employee severance costs, refinery shutdown costs and an income tax charge related to a planned divestiture.
(c) Includes a non-taxable gain of $951 million related to an asset sale, partially offset by after-tax charges totaling $40 million for employee severance, refinery shutdown costs and other exit costs.
(d) Includes an after-tax gain of $143 million resulting from the liquidation of LIFO inventories, largely offset by after-tax charges totaling $128 million related to a non-cash mark-to-market adjustment, employee severance costs, refinery shutdown costs, and other charges.
(e) Includes after-tax gains of $1,472 million related to asset sales and the liquidation of LIFO inventories, as well as a deferred tax benefit of $674 million which represents the effect of Denmark’s enacted changes to the hydrocarbon income tax law, partially offset by after-tax charges of $540 million related to asset impairments, dry hole expenses, severance and other exit costs, income tax charges, refinery shutdown costs, and other charges.
(f) Includes an after-tax gain of $36 million related to an asset sale.
(g) Includes an after-tax charge of $36 million related to an asset impairment.
(h) Includes an after-tax gain of $349 million related to an asset sale, partially offset by after-tax charges of $116 million for asset impairments and $56 million to write-off the Corporation’s exploration assets in Peru and an income tax charge of $115 million to reflect a change in the United Kingdom supplementary income tax rate applicable to deductions for dismantlement expenditures.
(i) Includes an after-tax charge of $192 million for an asset impairment, an income tax charge of $86 million and after-tax charge of $33 million for asset impairments and other charges, partially offset by an after-tax gain of $172 million related to an asset sale and after-tax income of $104 million from the partial liquidation of LIFO inventories.
The results of operations for the periods reported herein should not be considered as indicative of future operating results.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2013, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of December 31, 2013.
There was no change in internal controls over financial reporting identified in the evaluation required by paragraph (d) of Rules 13a-15 or 15d-15 in the quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, internal controls over financial reporting.
Management’s report on internal control over financial reporting and the attestation report on the Corporation’s internal controls over financial reporting are included in Item 8 of this annual report on Form 10-K.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information relating to Directors is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the 2014 annual meeting of stockholders.
The Corporation has adopted a Code of Business Conduct and Ethics applicable to the Corporation’s directors, officers (including the Corporation’s principal executive officer and principal financial officer) and employees. The Code of Business Conduct and Ethics is available on the Corporation’s website. In the event that we amend or waive any of the provisions of the Code of Business Conduct and Ethics that relate to any element of the code of ethics definition enumerated in Item 406(b) of Regulation S-K, we intend to disclose the same on the Corporation’s website at www.hess.com.
Information relating to the audit committee is incorporated herein by reference to “Election of Directors” from the registrant’s definitive proxy statement for the 2014 annual meeting of stockholders.
Executive Officers of the Registrant
The following table presents information as of February 1, 2014 regarding executive officers of the Registrant:
Name
Age
Office Held*
Year Individual
Became an
Executive
Officer
John B. Hess
Chief Executive Officer and Director
Gregory P. Hill
Executive Vice President and President
of Worldwide Exploration and Production
Timothy B. Goodell
Senior Vice President and General Counsel
John P. Rielly
Senior Vice President and Chief Financial Officer
Mykel J. Ziolo
Senior Vice President
Eric S. Fishman
Vice President and Treasurer
* All officers referred to herein hold office in accordance with the By-laws until the first meeting of the Directors following the annual meeting of stockholders of the Registrant and until their successors shall have been duly chosen and qualified. Each of said officers was elected to the office opposite his name on May 16, 2013, except for Mr. Fishman who was elected to the office September 1, 2013.
Each of the above officers has been employed by the Registrant or its subsidiaries in various managerial and executive capacities for more than five years.
Item 11. Executive Compensation
Information relating to executive compensation is incorporated herein by reference to “Election of Directors - Executive Compensation and Other Information,” from the Registrant’s definitive proxy statement for the 2014 annual meeting of stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information pertaining to security ownership of certain beneficial owners and management is incorporated herein by reference to “Election of Directors - Ownership of Voting Securities by Certain Beneficial Owners” and “Election of Directors - Ownership of Equity Securities by Management” from the Registrant’s definitive proxy statement for the 2014 annual meeting of stockholders.
See Equity Compensation Plans in Item 5 for information pertaining to securities authorized for issuance under equity compensation plans.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information relating to this item is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the 2014 annual meeting of stockholders.
Item 14. Principal Accounting Fees and Services
Information relating to this item is incorporated by reference to “Ratification of Selection of Independent Auditors” from the Registrant’s definitive proxy statement for the 2014 annual meeting of stockholders.
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a) 1. and 2. Financial statements and financial statement schedules
The financial statements filed as part of this Annual Report on Form 10-K are listed in the accompanying index to financial statements and schedules in Item 8, Financial Statements and Supplementary Data.
3. Exhibits
3(1)
Restated Certificate of Incorporation of Registrant, including amendment thereto dated May 3, 2006 incorporated by reference to Exhibit 3 of Registrant’s Form 10-Q for the three months ended June 30, 2006.
3(2)
Certificate of Amendment to the Restated Certificate of Incorporation of the Registrant, dated May 22, 2013, incorporated by reference to Exhibit 3(1) of Form 8-K of the Registrant filed on May 22, 2013.
3(3)
By-laws of Registrant incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on August 13, 2013.
4(1)
Five-Year Credit Agreement dated as of April 14, 2011, among Registrant, certain subsidiaries of Registrant, J.P. Morgan Chase Bank, N.A. as lender and administrative agent, and the other lenders party thereto, incorporated by reference to Exhibit 10(1) of Form 8-K of Registrant filed on April 18, 2011.
4(2)
Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999.
4(3)
First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999.
4(4)
Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001.
4(5)
Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on March 1, 2002.
4(6)
Indenture dated as of March 1, 2006 between Registrant and The Bank of New York Mellon as successor to JP Morgan Chase, as Trustee, including form of Note. Incorporated by reference to Exhibit 4 to Registrant’s Form S-3ASR filed with the Securities and Exchange Commission on March 1, 2006.
4(7)
Form of 2014 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase as Trustee. Incorporated by reference to Exhibit 4(1) to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009.
4(8)
Form of 2019 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase, as Trustee. Incorporated by reference to Exhibit 4(2) to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009.
4(9)
Form of 6.00% Note, incorporated by reference to Exhibit 4(1) to the Form 8-K of Registrant filed on December 15, 2009.
4(10)
Form of 5.60% Note incorporated by reference to Exhibit 4(1) to the Form 8-K of Registrant filed on August 12, 2010. Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.
10(1)*
Incentive Cash Bonus Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on March 8, 2013.
10(2)*
Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(3)*
Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for fiscal year ended December 31, 2006.
10(4)*
Performance Incentive Plan for Senior Officers, as amended, as approved by stockholders on May 4, 2011, incorporated by reference to Annex A to the definitive proxy statement of the Registrant filed on March 25, 2011.
10(5)*
Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.
10(6)*
Amendment dated December 31, 2006 to Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(10) of Form 10-K of Registrant for fiscal year ended December 31, 2006.
10(7)*
Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(8)*
Second Amended and Restated 1995 Long-term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(9)*
2008 Long-term Incentive Plan, incorporated by reference to Annex B to Registrant’s definitive proxy statement filed on March 27, 2008.
10(10)*
First Amendment dated March 3, 2010 and approved May 5, 2010 to Registrant’s 2008 Long-term Incentive Plan, incorporated by reference to Annex B of Registrant’s definitive proxy statement filed on March 25, 2010.
10(11)*
Forms of Awards under Registrant’s 2008 Long-term Incentive Plan incorporated by reference to Exhibit 10(14) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009.
10(12)*
Form of Performance Award Agreement under Registrant’s 2008 Long-term Incentive Plan incorporated by reference to Exhibit 10(2) of Form 8-K of Registrant filed on March 13, 2012.
10(13)*
Modified Form of Restricted Stock Award Agreement under Registrant’s 2008 Long-term Incentive Plan incorporated by reference to Exhibit 10(3) of Form 8-K of Registrant filed on March 13, 2012.
10(14)*
Second Amendment dated March 23, 2012 and approved May 2, 2012 to Registrant’s 2008 Long-term Incentive Plan, incorporated by reference to Annex A of Registrant’s definitive proxy statement filed on March 23, 2012.
10(15)*
Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant filed on January 4, 2007.
10(16)*
Amended and Restated Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and F. Borden Walker, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended June 30, 2009. A substantially identical agreement (differing only in the signatories thereto) was entered into between Registrant and John B. Hess.
10(17)*
Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and John P. Rielly incorporated by reference to Exhibit 10(17) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (including the named executive officers, other than those referred to in Exhibit 10(17)).
10(18)*
Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
10(19)*
Agreement between Registrant and Gregory P. Hill relating to his compensation and other terms of employment, incorporated by reference to Item 5.02 of Form 8-K of Registrant filed January 7, 2009.
10(20)*
Agreement between Registrant and Timothy B. Goodell relating to his compensation and other terms of employment incorporated by reference to Exhibit 10(20) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009.
10(21)*
Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.
10(22)
Agreement by and among Hess Corporation, Elliott Associates, L.P. and Elliott International, L.P. dated as of May 16, 2013, incorporated by reference to Exhibit 99(1) of Form 8-K of the Registrant filed on May 22, 2013.
Subsidiaries of Registrant.
23(1)
Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 28, 2014.
23(2)
Consent of DeGolyer and MacNaughton dated February 28, 2014.
31(1)
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
31(2)
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
32(1)
Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
32(2)
Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
99(1)
Letter report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consulting Firm, dated February 7, 2014, on proved reserves audit as of December 31, 2013 of certain properties attributable to Registrant.
101(INS)
XBRL Instance Document
101(SCH)
XBRL Schema Document
101(CAL)
XBRL Calculation Linkbase Document
101(LAB)
XBRL Labels Linkbase Document
101(PRE)
XBRL Presentation Linkbase Document
101(DEF)
XBRL Definition Linkbase Document
* These exhibits relate to executive compensation plans and arrangements.
(b) Reports on Form 8-K
During the three months ended December 31, 2013, Registrant filed or furnished the following report on Form 8-K:
1. Filing dated October 30, 2013 reporting under Items 2.02 and 9.01, and a news release dated October 30, 2013 reporting results for the third quarter of 2013.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 28th day of February 2014.
HESS CORPORATION
(Registrant)
By
/s/ JOHN P. RIELLY
(John P. Rielly)
Senior Vice President and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ JOHN B. HESS
John B. Hess
Director and
Chief Executive Officer
(Principal Executive Officer)
February 28, 2014
/s/ DR. MARK R. WILLIAMS
Dr. Mark R. Williams
Director and
Chairman of the Board
February 28, 2014
/s/ RODNEY F. CHASE
Rodney F. Chase
Director
February 28, 2014
/s/ HARVEY GOLUB
Harvey Golub
Director
February 28, 2014
/s/ EDITH E. HOLIDAY
Edith E. Holiday
Director
February 28, 2014
/s/ JOHN KRENICKI, JR.
John Krenicki, Jr.
Director
February 28, 2014
/s/ DR. RISA LAVIZZO-MOUREY
Dr. Risa Lavizzo-Mourey
Director
February 28, 2014
/s/ DAVID MCMANUS
David McManus
Director
February 28, 2014
/s/ DR. KEVIN O. MEYERS
Dr. Kevin O. Meyers
Director
February 28, 2014
/s/ JOHN H. MULLIN, III
John H. Mullin, III
Director
February 28, 2014
/s/ JAMES H. QUIGLEY
James H. Quigley
Director
February 28, 2014
/s/ FREDRIC G. REYNOLDS
Fredric G. Reynolds
Director
February 28, 2014
/s/ JOHN P. RIELLY
John P. Rielly
Senior Vice President and Chief
Financial Officer
(Principal Financial and Accounting Officer)
February 28, 2014
/s/ WILLIAM G. SCHRADER
William G. Schrader
Director
February 28, 2014
/s/ ROBERT N. WILSON
Robert N. Wilson
Director
February 28, 2014
Schedule II
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2013, 2012 and 2011
Report of Independent Auditors
The Members
HOVENSA L.L.C.
We have audited the accompanying statements of operations, comprehensive loss and (accumulated deficit) retained earnings, and cash flows of HOVENSA L.L.C. (“the Company”) for the year ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the results of the Company’s operations and its cash flows for the year ended December 31, 2011 in conformity with U.S. generally accepted accounting principles.
/s/ ERNST & YOUNG LLP
February 27, 2012
New York, New York
HOVENSA L.L.C.
BALANCE SHEETS
(Dollars in thousands)
See accompanying notes to financial statements.
HOVENSA L.L.C.
STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS)
AND (ACCUMULATED DEFICIT) RETAINED EARNINGS
(Dollars in thousands)
See accompanying notes to financial statements.
HOVENSA L.L.C.
STATEMENTS OF CASH FLOWS
(Dollars in thousands)
See accompanying notes to financial statements.
HOVENSA L.L.C.
NOTES TO FINANCIAL STATEMENTS
(Dollars in thousands)
1. Basis of Financial Statements and Significant Accounting Policies
Nature of Business
Background: HOVENSA L.L.C. (the “Company” or “HOVENSA”) was formed as a 50/50 joint venture between subsidiaries of Petroleos de Venezuela, SA. (“PDVSA”) and Hess Corporation (“Hess”), to own and operate the Company’s refinery located in St. Croix, United States (U.S.) Virgin Islands. The Company’s members are PDVSA V.I., Inc., a subsidiary of PDVSA, and Hess Oil Virgin Islands Corp. (“HOVIC”), a subsidiary of Hess. Through January 2012, the Company purchased crude oil from PDVSA, Hess and third parties, and manufactured and sold petroleum products primarily to PDVSA and Hess. Since January 2012, the Company has operated the facility as an oil storage terminal.
HOVENSA operates under a Concession Agreement with the Government of the U.S. Virgin Islands. The original Concession Agreement was entered into on September 1, 1965. On November 5, 2013, HOVENSA entered into the Fourth Amendment to the Concession Agreement that provides for a process to sell the oil refinery and related facilities, which has commenced. The Company has opened a data room and has retained an investment advisor. The Concession Agreement can be extended with Virgin Islands government approval, which has occurred on four previous occasions.
Shutdown of Refinery: In December 2011, the Company’s members agreed to shut down refining operations effective January 18, 2012. As a result of this decision, the Company recorded noncash charges totaling $2,072,600 in December 2011 to fully impair its property, plant and equipment and recognize certain other expenses related to the shutdown decision. Following the refinery shutdown, the Company redeemed its outstanding debt, liquidated a majority of its inventory and settled a portion of its liabilities. In 2012, additional shutdown related charges totaling $152,759 were recorded, primarily for the estimated legal obligations for hydrocarbon removal and tank cleaning costs.
Basis of Presentation
The accompanying financial statements of HOVENSA have been prepared in conformity with United States generally accepted accounting principles (“U.S. GAAP”). As further explained in Notes 2 and 3 below, the Company fully impaired its property, plant and equipment and recorded certain refinery shutdown costs at December 31, 2011. Refinery shutdown activities occurred in 2012 and 2013. The Company received financial support from the members in 2012 to fund a portion of the expenditures for the refinery shutdown and conversion to an oil storage terminal.
The members’ primary objective is to sell the refinery and related facilities. The Company believes that it has cash reserves that are only sufficient to fund its operations through the first three quarters of 2014 and the members currently do not anticipate providing any additional funding to the Company. If an agreement to sell the refinery cannot be reached, the Company will likely not be able to continue operating the facility as an oil storage terminal.
Use of Estimates
In preparing financial statements in conformity with U.S. GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and revenues and expenses in the statement of operations. Actual results could differ from those estimates. Among the estimates made by management are asset impairments, refinery shutdown costs, inventory and other asset valuations, legal and environmental obligations and pension liabilities.
Revenue Recognition
The Company recognizes revenues from the sale of petroleum products when title passes to the customer, which generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements.
In addition, the Company provides storage and other related services for third-party customers. Tank storage and related revenue is recognized in the period the service is provided. Product stored remains the property of these third-party customers.
HOVENSA L.L.C.
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands)
Cash and Cash Equivalents
Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have maturities of three months or less when acquired.
Inventories
Inventories of crude oil and refined products used in refining operations were valued at the lower of last-in, first-out (“LIFO”) cost or market. Other inventories, including refined products purchased for resale or used in operations, as well as materials and supplies are valued at the lower of average cost or market.
Depreciation
Depreciation of refinery facilities through December 31, 2011 was determined principally on the units-of-production method based on estimated production volumes. Depreciation of all other equipment was determined on the straight-line method based on estimated useful lives.
Maintenance and Repairs
Maintenance and repairs are expensed as incurred.
Impairment of Long-Lived Assets
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The impairment recognized is the amount by which the carrying amount exceeds the estimated fair market value of the assets.
Asset Retirement Obligations
Asset retirement obligations must be recorded at fair value in the period in which it is determined that a legal obligation exists and a reasonable estimate of the fair value of the liability can be made.
Environmental Expenditures
Liabilities for future remediation costs are recorded when environmental assessments or remedial efforts are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals generally are based on the completion of investigations or other studies or a commitment to a formal plan of action. Environmental liabilities are based on best estimates of probable undiscounted future costs using currently available technology and applying current regulations. Such accruals are adjusted as further information develops or circumstances change.
Income Taxes
The Company is a limited liability company and, as a result, income taxes are the responsibility of the members. Accordingly, no effect of income tax has been recognized in the accompanying financial statements.
Retirement Plans
The Company recognizes on its balance sheet the underfunded status of its defined benefit retirement plans measured as the difference between the fair value of plan assets and the benefit obligations. The benefit obligation is the projected benefit obligation
HOVENSA L.L.C.
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands)
in the case of the non-contributory defined benefit pension plan and the projected post-retirement benefit obligation for the post-retirement medical plan. The Company recognizes the net changes in the plan assets and benefit obligations of its defined benefit retirement plans in the year in which such changes occur.
Prior service costs and gains and losses in excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service period of active employees.
The determination of the obligations and expenses related to these plans are based on several actuarial assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets and rate of future increases in compensation levels. These assumptions represent estimates made by the Company, some of which can be affected by external factors.
2. Asset Impairment and Refinery Shutdown Related Charges
On January 18, 2012, HOVENSA announced the decision to shut down its refinery operations after experiencing substantial operating losses due to global economic conditions and competitive disadvantages versus other refiners. Such losses were incurred despite efforts to improve operating performance by reducing refining capacity to 350,000 barrels per day from 500,000 barrels per day in the first half of 2011. Operating losses were also projected to continue. The Company prepared an impairment analysis as of December 31, 2011, which indicated that undiscounted future cash flows would not recover the carrying value of its assets. As a result, the Company recorded an impairment charge of $1,900,349 representing the difference between the carrying value and the estimated fair market value of property, plant and equipment at December 31, 2011. Estimated fair value was determined based on discounted future cash flows (a Level 3 fair value measure). In addition, the Company recorded other charges totaling $172,251 for obligations incurred in 2011 related to the decision to shut down the refinery, including recognition of legally required employee and contractor severance costs of $66,200 and reductions in carrying value of warehouse inventory and other assets totaling $106,051.
During 2012, the Company recorded a charge $175,000 for estimated obligations incurred due to hydrocarbon removal and tank cleaning costs, that became legal obligations upon shutdown of the refinery. In addition, the Company recorded a charge of $23,408 in 2012 to write down warehouse inventory and other assets and reduced its allowance for doubtful accounts by $45,649 upon collection of a previously written-off receivable.
3. Future Refinery Shutdown Expenditures
The Company is expected to incur additional refinery shutdown costs in excess of amounts that can be accrued under US GAAP, including costs related to the preservation of refinery process equipment, enhanced employee and contractor severance and benefits, estimated losses on long-term contracts and other costs. Of the amounts that were accrued, the following is the movement in the shutdown reserve:
The shutdown reserve is reflected in accrued liabilities on the balance sheet.
HOVENSA L.L.C.
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands)
4. Related Party Transactions
During 2012 and 2011, HOVENSA received financial support from its members primarily by delaying the normal timing of payments to PDVSA for crude oil purchases, as well as accelerating payments from Hess for refined product sales. At December 31, 2012 and 2011, interest bearing financial support provided by both members in the aggregate of $1,622,000 and $654,000, respectively, is recorded as a current liability in the balance sheet. The Company incurred interest expense of $85,155 in 2013, and $80,148 in 2012, and $14,278 in 2011 on payables to its members for their financial support.
The Company had long-term crude oil supply agreements with Petroleum Marketing International (“Petromar”) a subsidiary of PDVSA, under which Petromar agreed to sell to HOVENSA a monthly average of 155,000 barrels per day of Mesa crude oil and 115,000 barrels per day of Merey crude oil. The Company also had a product sales agreement with Hess and Petromar that requires Hess and Petromar each to purchase after any sales of refined products by HOVENSA to third parties, 50% of HOVENSA’s gasoline, distillate, residual fuel and other products at market prices. Purchases and sales under these agreements ceased on April 1, 2012 following the shutdown of refining operations.
A summary of all material transactions between the Company, its members and affiliates follows:
5. Inventories
Inventories as of December 31 were as follows:
During 2013 and 2012, the Company liquidated LIFO inventories that are carried at below market costs, which improved operating results by approximately $10,000 and $745,000, respectively. During 2014, the Company intends to liquidate its remaining crude oil, refined and other finished products inventories.
HOVENSA L.L.C.
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands)
6. Tax Exempt Revenue Bonds and Other Long-Term Debt
During 2012, the Company redeemed $355,683 of tax-exempt revenue bonds. The terms of the tender offer included a purchase price at par value, plus accrued but unpaid interest up to the purchase date, subject to the terms of the offering document. In conjunction with the redemption of the tax-exempt revenue bonds, the Company’s debt service fund was liquidated.
7. Environmental Matters
In 2011, the Company signed a Consent Decree with the U.S. Environmental Protection Agency (EPA) and the United States Virgin Islands, which among other things requires the Company to install equipment and implement additional operating procedures to reduce emissions over the next 10 years. The cost of installing this equipment would have been approximately $700,000. Since the refining facilities were shut down in 2012 and the Company reached an agreement in 2013 with the United States Virgin Islands to engage in a sale process, the Company believes it will not be required to make the material capital expenditures outlined in the Consent Decree. Under the terms of the Consent Decree, the Company paid a penalty of $5,375 in 2011.
In the normal course of its business, the Company records liabilities for future environmental remediation expenditures when such environmental obligations are probable and reasonably estimable.
The Company is required to provide financial assurance to the EPA in connection with various forms of environmental compliance. The required financial assurance totaled approximately $47,000 at December 31, 2013 and $41,000 at December 31, 2012. This requirement was met in 2013 by establishing a trust for $38,000, which is reflected in other assets on the balance sheet, and posting a letter of credit for $9,000. In 2012, the Company met the requirement by posting a letter of credit.
8. Contingencies
The Company is subject to loss contingencies with respect to various lawsuits, claims and other proceedings, including environmental matters. A liability is recognized in the Company’s financial statements when it is probable a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, the Company discloses the nature of those contingencies. In management’s opinion, based upon currently known facts and circumstances, the outcome of such loss contingencies will not have a material adverse effect on the Company’s financial condition, results of operations and cash flows.
9. Retirement Plans
The Company has a funded non-contributory, defined benefit pension plan for substantially all of its employees. The plan provides defined benefits based on years of service and final average salary. At December 31, 2013 and 2012, the actuarial assumptions for the determination of the projected benefit obligation reflect the transition of the refinery to an oil storage terminal. The non-contributory defined benefit pension plan will remain in place and meet future obligations in accordance with terms of the plan, but terminated employees will no longer earn service toward future benefits.
HOVENSA L.L.C.
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands)
The following table reconciles the projected benefit obligation and fair value of plan assets and shows the funded status of the pension plan:
The accumulated benefit obligation was $120,287 at December 31, 2013 and $137,831 at December 31, 2012.
Components of funded pension expense consisted of the following:
The actuarial assumptions used in the Company’s pension plan were as follows:
HOVENSA L.L.C.
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands)
The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year while the assumptions used to determine benefit obligations were established at each year-end. The net periodic benefit cost and the actuarial present value of benefit obligations are based on actuarial assumptions that are reviewed on an annual basis. The discount rate is developed based on a portfolio of high-quality fixed-income investments that matches the maturity of the plan obligations. The overall expected return on plan assets is developed from the expected future returns for each asset category, weighted by the expected allocation of pension assets to that asset category. The Company engages an independent investment consultant to assist in the development of expected returns.
The Company’s pension plan assets by category are as follows:
Target investment allocations are 73% debt securities and 27% equity securities. Asset allocations are rebalanced on a regular basis throughout the year to bring assets to within a 2-3% range of target levels. Target allocations take into account analyses performed by the Company’s pension consultant to optimize long-term risk/return relationships. All assets are highly liquid and may be readily adjusted to provide liquidity for current benefit payment requirements.
For purposes of valuing pension investments, a hierarchy for the inputs is used to measure fair value based on the source of the input, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3).
The following tables provide the fair value hierarchy of the financial assets of the qualified pension plan as of December 31, 2013 and 2012:
Cash and short-term investment funds consist of cash on hand, which is invested in a short-term investment fund that provides for daily investments and redemptions and is valued and carried at a $1 net asset value (NAV) per fund share.
Equities consist of registered mutual fund investments whose diversified holdings primarily include common stock securities issued by U.S. and non-U.S. corporations, respectively. Mutual fund shares are valued daily, with the NAV per fund share published at the close of each business day. These investments are classified as Level 1.
Fixed income securities consist of registered mutual fund investments whose diversified holdings primarily include U.S. Treasury securities, corporate bonds and mortgage backed securities.
HOVENSA L.L.C.
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Dollars in thousands)
HOVENSA has budgeted contributions to its funded pension plan of approximately $13,000 in 2014.
Estimated future pension benefit payments are as follows:
The Company also maintains an unfunded post-retirement medical plan that provides health benefits to certain qualified retirees from ages 55 through 65. The projected benefit obligation for this plan was approximately $11,160 as of December 31, 2013 and $11,325 as of December 31, 2012. The decrease in the projected benefit obligation includes a change in actuarial assumptions to reflect the transition of the refinery to an oil storage terminal. This plan remains in place, but terminated employees will no longer earn service toward future benefits.
EXHIBIT INDEX
3(1)
Restated Certificate of Incorporation of Registrant, including amendment thereto dated May 3, 2006 incorporated by reference to Exhibit 3 of Registrant’s Form 10-Q for the three months ended June 30, 2006.
3(2)
Certificate of Amendment to the Restated Certificate of Incorporation of the Registrant, dated May 22, 2013, incorporated by reference to Exhibit 3(1) of Form 8-K of the Registrant filed on May 22, 2013.
3(3)
By-laws of Registrant incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on August 13, 2013.
4(1)
Five-Year Credit Agreement dated as of April 14, 2011, among Registrant, certain subsidiaries of Registrant, J.P. Morgan Chase Bank, N.A. as lender and administrative agent, and the other lenders party thereto, incorporated by reference to Exhibit 10(1) of Form 8-K of Registrant filed on April 18, 2011.
4(2)
Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999.
4(3)
First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999.
4(4)
Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001.
4(5)
Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on March 1, 2002.
4(6)
Indenture dated as of March 1, 2006 between Registrant and The Bank of New York Mellon as successor to JP Morgan Chase, as Trustee, including form of Note. Incorporated by reference to Exhibit 4 to Registrant’s Form S-3ASR filed with the Securities and Exchange Commission on March 1, 2006.
4(7)
Form of 2014 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase as Trustee. Incorporated by reference to Exhibit 4(1) to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009.
4(8)
Form of 2019 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase, as Trustee. Incorporated by reference to Exhibit 4(2) to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009.
4(9)
Form of 6.00% Note, incorporated by reference to Exhibit 4(1) to the Form 8-K of Registrant filed on December 15, 2009.
4(10)
Form of 5.60% Note incorporated by reference to Exhibit 4(1) to the Form 8-K of Registrant filed on August 12, 2010. Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.
10(1)*
Incentive Cash Bonus Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on March 8, 2013.
10(2)*
Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(3)*
Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for fiscal year ended December 31, 2006.
10(4)*
Performance Incentive Plan for Senior Officers, as amended, as approved by stockholders on May 4, 2011, incorporated by reference to Annex A to the definitive proxy statement of the Registrant filed on March 25, 2011.
10(5)*
Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.
10(6)*
Amendment dated December 31, 2006 to Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(10) of Form 10-K of Registrant for fiscal year ended December 31, 2006.
10(7)*
Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(8)*
Second Amended and Restated 1995 Long-term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(9)*
2008 Long-term Incentive Plan, incorporated by reference to Annex B to Registrant’s definitive proxy statement filed on March 27, 2008.
10(10)*
First Amendment dated March 3, 2010 and approved May 5, 2010 to Registrant’s 2008 Long-term Incentive Plan, incorporated by reference to Annex B of Registrant’s definitive proxy statement filed on March 25, 2010.
10(11)*
Forms of Awards under Registrant’s 2008 Long-term Incentive Plan incorporated by reference to Exhibit 10(14) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009.
10(12)*
Form of Performance Award Agreement under Registrant’s 2008 Long-term Incentive Plan incorporated by reference to Exhibit 10(2) of Form 8-K of Registrant filed on March 13, 2012.
10(13)*
Modified Form of Restricted Stock Award Agreement under Registrant’s 2008 Long-term Incentive Plan incorporated by reference to Exhibit 10(3) of Form 8-K of Registrant filed on March 13, 2012.
10(14)*
Second Amendment dated March 23, 2012 and approved May 2, 2012 to Registrant’s 2008 Long-term Incentive Plan, incorporated by reference to Annex A of Registrant’s definitive proxy statement filed on March 23, 2012.
10(15)*
Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant filed on January 4, 2007.
10(16)*
Amended and Restated Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and F. Borden Walker, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended June 30, 2009. A substantially identical agreement (differing only in the signatories thereto) was entered into between Registrant and John B. Hess.
10(17)*
Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and John P. Rielly incorporated by reference to Exhibit 10(17) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (including the named executive officers, other than those referred to in Exhibit 10(17)).
10(18)*
Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
10(19)*
Agreement between Registrant and Gregory P. Hill relating to his compensation and other terms of employment, incorporated by reference to Item 5.02 of Form 8-K of Registrant filed January 7, 2009.
10(20)*
Agreement between Registrant and Timothy B. Goodell relating to his compensation and other terms of employment incorporated by reference to Exhibit 10(20) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009.
10(21)*
Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.
10(22)
Agreement by and among Hess Corporation, Elliott Associates, L.P. and Elliott International, L.P. dated as of May 16, 2013, incorporated by reference to Exhibit 99(1) of Form 8-K of the Registrant filed on May 22, 2013.
Subsidiaries of Registrant.
23(1)
Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 28, 2014.
23(2)
Consent of DeGolyer and MacNaughton dated February 28, 2014.
31(1)
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
31(2)
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
32(1)
Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
32(2)
Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
99(1)
Letter report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consulting Firm, dated February 7, 2014, on proved reserves audit as of December 31, 2013 of certain properties attributable to Registrant.
101(INS)
XBRL Instance Document
101(SCH)
XBRL Schema Document
101(CAL)
XBRL Calculation Linkbase Document
101(LAB)
XBRL Labels Linkbase Document
101(PRE)
XBRL Presentation Linkbase Document
101(DEF)
XBRL Definition Linkbase Document
* These exhibits relate to executive compensation plans and arrangements.