HESS CORP
Item 1A. Risk Factors
Our business activities and the value of our securities are subject to significant risks, including the risk factors described below. These risk factors 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, liquidity, financial condition and future earnings are highly dependent on the benchmark market prices of crude oil, natural gas liquids and natural gas, and our associated realized price differentials, which are volatile and influenced by numerous factors beyond our control. The major foreign oil producing countries, including members of OPEC, may 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 may have a significant impact on the oil markets. Other factors include, but are not limited to: worldwide and domestic supplies of and demand for crude oil, natural gas liquids and natural gas, political conditions and events (including instability, changes in governments, or armed conflict) around the world and in particular in crude oil or natural gas producing regions, the cost of exploring for, developing and producing crude oil, natural gas liquids and natural gas, the price and availability of alternative fuels or other forms of energy, the effect of energy conservation and environmental protection efforts and overall economic conditions globally. The sentiment of 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. Average prices for 2016 were $43.47 per barrel for WTI (2015: $48.76; 2014: $92.91) and $45.13 per barrel for Brent (2015: $53.60; 2014: $99.45). In order to manage the potential volatility of cash flows and credit requirements, we maintain significant bank credit facilities. An inability to access, renew or replace such credit facilities or access other sources of funding as they mature would negatively impact our liquidity.
If we fail to successfully increase our reserves, our future crude oil and natural gas production will be adversely impacted. We own or have access to a finite amount of oil and gas reserves which will be depleted over time. Replacement of oil and gas production and reserves, including proved undeveloped reserves, is subject to successful exploration drilling, development activities, and enhanced recovery programs. Therefore, future oil and gas production is dependent on technical success in finding and developing additional hydrocarbon reserves. Exploration activity involves the interpretation of seismic and other geological and geophysical data, which does not always successfully predict the presence of commercial quantities of hydrocarbons. Drilling risks include unexpected adverse conditions, irregularities in pressure or formations, equipment failure, blowouts and weather interruptions. Future developments may be affected by unforeseen reservoir conditions which negatively affect recovery factors or flow rates. Reserve replacement can also be achieved through acquisition. Similar risks, however, may be encountered in the production of oil and gas on properties acquired from others. In addition to the technical risks to reserve replacement, replacing reserves and developing future production is also influenced by the price of crude oil and natural gas and costs of drilling and development activities. Persistent lower crude oil and natural gas prices, such as those currently prevailing, may have the effect of reducing capital available for exploration and development activity and may render certain development projects uneconomic or delay their completion and may result in negative revisions to existing reserves while increasing drilling and development costs could negatively affect expected economic returns.
There are inherent uncertainties in estimating quantities of proved reserves and discounted future net cash flows, and actual quantities may be lower than estimated. Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues from those reserves. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities of our proved reserves and the related future net revenues. In addition, reserve estimates may be subject to downward or upward changes based on production performance, purchases or sales of properties, results of future development, prevailing oil and gas prices, production sharing contracts, which may decrease reserves as crude oil and natural gas prices increase, and other factors. Crude oil prices declined significantly in 2015 and to a lesser extent in 2016 resulting in reductions to our reported proved reserves. If crude oil prices in 2017 average below prices used to determine proved reserves at December 31, 2016, it could have an adverse effect on our estimated proved reserves and the value of our business. See Crude Oil and Natural Gas Reserves in Critical Accounting Policies and Estimates in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
We do not always control decisions made under joint operating agreements and the parties under such agreements may fail to meet their obligations. We conduct many of our E&P 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, anti-bribery or anti-corruption laws, as well as other political developments may affect our operations.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all. The exploration, development and production of crude oil and natural gas involves substantial costs, which may not be fully funded from operations. For example, in 2016, we had a significant net loss and, if commodity prices remain low through 2017, we are forecasting a net loss for 2017. Two of the three major credit rating agencies that rate our debt have assigned an investment grade rating. In February 2016, Standard and Poor’s Ratings Services (S&P) lowered our investment grade credit rating one notch to BBB- with stable outlook and Moody’s Investors Service (Moody’s) lowered our credit rating to Ba1 with stable outlook, which is below investment grade. In December 2016, Fitch Ratings (Fitch) lowered our investment grade credit rating one notch to BBB- with stable outlook. In February 2017, S&P re-affirmed our investment grade credit rating of BBB- with stable outlook. Although, currently we do not have any borrowings under our long-term credit facility, further ratings downgrades, continued weakness in the oil and gas industry or negative outcomes within commodity and financial markets could adversely impact our access to capital markets by increasing the costs of financing, or by impacting our ability to obtain financing on satisfactory terms, or at all. In addition, further ratings downgrades may require that we issue letters of credit or provide other forms of collateral under certain contractual requirements. Any inability to access capital markets could adversely impact our financial adaptability and our ability to execute our strategy and may also expose us to heightened exposure to credit risk.
Political instability in areas where we operate can adversely affect our business. Some of the international areas in which we operate, and the partners with whom we operate, are politically less stable than other areas and partners and may be subject to civil unrest, conflict, insurgency, geographic territorial border disputes, corruption, security risks and labor unrest. Political and civil unrest in North Africa and the Middle East has affected and may affect our operations in these areas as well as oil and gas markets generally. The threat of terrorism around the world also poses additional risks to the operations of the oil and gas industry.
Our oil and gas operations are subject to environmental risks and environmental laws and regulations that can result in significant costs and liabilities. Our oil and gas operations, like those of the industry, are subject to environmental risks such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for pollution or other environmental damage. Our operations are also subject to numerous U.S. federal, state, local and foreign environmental laws and regulations. Non-compliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial clean-ups and natural resource damages or other liabilities. In addition, increasingly stringent environmental regulations have resulted and will likely continue to result in higher capital expenditures and operating expenses for us and the oil and gas industry in general. Similarly, we have material legal obligations to dismantle, remove and abandon production facilities and wells that will occur many years in the future, in most cases. These estimates may be impacted by future changes in regulations and other uncertainties.
Concerns have been raised in certain jurisdictions where we have operations concerning the safety and environmental impact of the drilling and development of shale oil and gas resources, particularly hydraulic fracturing, water usage, flaring of associated natural gas and air emissions. While we believe that these operations can be conducted safely and with minimal impact on the environment, regulatory bodies are responding to these concerns and may impose moratoriums and new regulations on such drilling operations that would likely have the effect of prohibiting or delaying such operations and increasing their cost.
Climate change initiatives may result in significant operational changes and expenditures, reduced demand for our products and adversely affect our business. We recognize that climate change is a global environmental concern. Continuing political and social attention to the issue of climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit greenhouse gas emissions. These agreements and measures may require significant equipment modifications, operational changes, taxes, or purchase of emission credits to reduce emission of greenhouse gases from our operations, which may result in substantial capital expenditures and compliance, operating, maintenance and remediation costs. In addition, our production is used to produce petroleum fuels, which through normal customer use may result in the emission of greenhouse gases. Regulatory initiatives to reduce the use of these fuels may reduce demand for crude oil and other hydrocarbons and have an adverse effect on our
sales volumes, revenues and margins. The imposition and enforcement of stringent greenhouse gas emissions reduction targets could severely and adversely impact the oil and gas industry and significantly reduce the value of our business.
Our industry is highly competitive and many of our competitors are larger and have greater resources than we have. The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies in each of our activities, including acquiring rights to explore for crude oil and natural gas. Many competitors, 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 could significantly increase 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 us against liability from all potential consequences and damages. Moreover, some forms of insurance may be unavailable in the future or be available only on terms that are deemed economically unacceptable.
Significant time delays between the estimated and actual occurrence of critical events associated with development projects may result in material negative economic consequences. We are involved in several large development projects and the completion of those projects may be delayed beyond what was originally anticipated. Such examples include, but are not limited to, delays in receiving necessary approvals from project members or regulatory agencies, timely access to necessary equipment, availability of necessary personnel, construction delays, unfavorable weather conditions and equipment failures. This may lead to delays and differences between estimated and actual timing of critical events. These delays could impact our future results of operations and cash flows.
Departures of key members from our senior management team, and/or difficulty in recruiting and retaining adequate numbers of experienced technical personnel, could negatively impact our ability to deliver on our strategic goals. The derivation and monitoring of successful strategies and related policies may be negatively impacted by the departure of key members of senior management. Moreover, an inability to recruit and retain adequate numbers of experienced technical and professional personnel in the necessary locations may prohibit us from executing our strategy in full or, in part, with a commensurate impact on shareholder value.
We are dependent on oilfield service companies for items including drilling rigs, equipment, supplies and skilled labor. An inability or significant delay in securing these services, or a high cost thereof, may result in material negative economic consequences. The availability and cost of drilling rigs, equipment, supplies and skilled labor will fluctuate over time given the cyclical nature of the E&P industry. As a result, we may encounter difficulties in obtaining required services or could face an increase in cost. These consequences may impact our ability to run our operations and to deliver projects on time with the potential for material negative economic consequences.
We manage commodity price and other risks through our risk management function but such activities may impede our ability to benefit from commodity price increases and can expose us to similar potential counterparty credit risk as impacts amounts due from the sale of hydrocarbons. We may enter into commodity price hedging arrangements to protect us from commodity price declines. These arrangements may, depending on the instruments used and the level of increases involved, limit any potential upside from commodity price increases. As with accounts receivable we may be exposed to potential economic loss should a counterparty be unable or unwilling to perform their obligations under the terms of a hedging agreement. 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.
Cyber-attacks targeting computer, telecommunications systems, and infrastructure used by the oil and gas industry may materially impact our business and operations. Computers and telecommunication systems are used to conduct our exploration, development and production activities and have become an integral part of our business. We use these systems to analyze and store financial and operating data and to communicate within our company and with outside business partners. Cyber-attacks could compromise our computer and telecommunications systems and result in disruptions to our business operations or the loss of our data and proprietary information. In addition, computers control oil and gas production, processing equipment, and distribution systems globally and are necessary to deliver our production to market. A cyber-attack against these operating systems, or the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or prevent delivery to markets, and make it difficult or impossible to accurately account for production and settle transactions. As a result, a cyber-attack could have a material adverse impact on
our cash flows and results of operations. We routinely experience attempts by external parties to penetrate and attack our networks and systems. Although such attempts to date have not resulted in any material breaches, disruptions, or loss of business critical information, our systems and procedures for protecting against such attacks and mitigating such risks may prove to be insufficient in the future and such attacks could have an adverse impact on our business and operations. In addition, as technologies evolve and these attacks become more sophisticated, we may incur significant costs to upgrade or enhance our security measures to protect against such attacks.
Item 1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have 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 us. The principal allegation in all cases was that gasoline containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. The majority of the cases asserted against us have been settled. In June 2014, the Commonwealth of Pennsylvania and the State of Vermont each filed independent lawsuits alleging that we and all major oil companies with operations in each respective state, have damaged the groundwater in those states by introducing thereto gasoline with MTBE. The Pennsylvania suit has been removed to Federal court and has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. The suit filed in Vermont is proceeding there in a state court. In September 2016, the State of Rhode Island also filed a lawsuit in Federal court alleging that we and other major oil companies damaged the groundwater in Rhode Island by introducing thereto gasoline with MTBE. An action brought by the Commonwealth of Puerto Rico was settled in conjunction with the Bankruptcy Court’s confirmation of HOVENSA’s Liquidation Plan, which is described below. The remaining open matters are not expected to have a material adverse effect on our financial condition.
In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the Lower Passaic River. The NJDEP is also seeking natural resource damages. The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned. We and over 70 companies entered into an Administrative Order on Consent with the Environmental Protection Agency (EPA) to study the same contamination; this work remains ongoing. We and other parties settled a cost recovery claim by the State of New Jersey and also agreed with EPA to fund remediation of a portion of the site. In April 2014, the EPA issued a Focused Feasibility Study (FFS) proposing to conduct bank-to-bank dredging of the lower eight miles of the Lower Passaic River at an estimated cost of $1.7 billion. On March 4, 2016, the EPA issued a Record of Decision (ROD) in respect of the lower eight miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion. The ROD does not address the upper nine miles of the Lower Passaic River, which may require additional remedial action. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given that the EPA has not selected a remedy for the entirety of the Lower Passaic River, total remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us because there are numerous other parties who we expect will share in the cost of remediation and damages and our former terminal did not store or use contaminants which are of the greatest concern in the river sediments and could not have contributed contamination along most of the river’s length.
In March 2014, we received an Administrative Order from EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. The remedy includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. EPA has estimated that this remedy will cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. Our alleged liability derives from our former ownership and operation of a fuel oil terminal adjacent to the Canal. We indicated to EPA that we would comply with the Administrative Order and are currently contributing funding for the Remedial Design based on an interim allocation of costs among the parties. At the same time, we are participating in an allocation process whereby neutral experts selected by the parties will determine the final shares of the Remedial Design costs to be paid by each of the participants. The parties have not yet addressed the allocation of costs associated with implementing the remedy that is currently being designed. This matter is not expected to have a material adverse effect on our financial condition.
On January 18, 2017, we entered into a Consent Decree with the North Dakota Department of Health resolving alleged non-compliance with North Dakota’s air pollution laws and provisions of the federal Clean Air Act. Pursuant to the Consent Decree, we are required to implement corrective actions, including implementation of a leak detection and repair program, at most of our existing facilities in North Dakota. We were assessed a base penalty of $922,000, which is subject to adjustment based on the date we complete corrective actions required under the terms of the Consent Decree. We made an initial penalty payment of $55,000 during the first quarter of 2017.
We periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties may be jointly and severally liable. For certain sites, such as those discussed above, the EPA’s claims or assertions of liability against us 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 our business or accounts 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.
We are from time to time involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. We 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 our financial condition, results of operations or cash flows.
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
Our common stock 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 returns on a $100 investment in our 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 13 oil and gas peer companies, including the Corporation (as disclosed in our 2016 Proxy Statement).
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
Holders
At December 31, 2016, there were 3,428 stockholders (based on the number of holders of record) who owned a total of 316,523,200 shares of common stock.
Dividends
In 2016, 2015 and 2014, cash dividends on common stock totaled $1.00 per share per year ($0.25 per quarter).
Share Repurchase Activities
Our share repurchase activities for the year ended December 31, 2016, were as follows:
(a)
Repurchased in open-market transactions. The average price paid per share was inclusive of transaction fees.
(b)
Includes 42,972 common shares repurchased at a price of $44.23 per common share on the open market in March, which were subsequently granted to Directors in accordance with the Non-Employee Directors’ Stock Award Plan. In addition, includes 1,083 common shares repurchased at a price of $47.00 per common share on the open market in September, which were subsequently granted to a new Director in accordance with the Non-Employee Directors’ Stock Award Plan.
(c)
Since initiation of the buyback program in August 2013, total shares repurchased through December 31, 2016 amounted to 64.1 million at a total cost of $5.4 billion (including transaction fees).
(d)
In March 2013, we announced that our Board of Directors approved a stock repurchase program that authorized the purchase of common stock up to a value of $4.0 billion. In May 2014, the share repurchase program was increased to $6.5 billion.
Equity Compensation Plans
Following is information related to our equity compensation plans at December 31, 2016.
(a)
This amount includes 6,591,944 shares of common stock issuable upon exercise of outstanding stock options. This amount excludes 1,015,379 performance share units (PSU) for which the number of shares of common stock to be issued may range from 0% to 200%, based on our total shareholder return (TSR) relative to the TSR of a predetermined group of peer companies over a three-year performance period ending December 31 of the year prior to settlement of the grant. In addition, this amount also excludes 3,100,659 shares of common stock issued as restricted stock pursuant to our equity compensation plans.
(b)
These securities may be awarded as stock options, restricted stock, performance share units or other awards permitted under our equity compensation plan.
(c)
We have a Non-Employee Director’s Stock Award Plan pursuant to which our non-employee directors received in aggregate $2 million in value of our common stock. These awards are made from shares we have purchased in the open market.
See Note 13, Share-based Compensation in Notes to Consolidated Financial Statements for further discussion of our 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 both our Consolidated Financial Statements and Accompanying Notes, and
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
Hess Corporation is a global Exploration and Production (E&P) company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Denmark, Equatorial Guinea, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Norway. The Bakken Midstream operating segment, which was established in the second quarter of 2015, provides fee-based services, including gathering, compressing and processing natural gas and fractionating natural gas liquids, or NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; and storing and terminaling propane, primarily in the Bakken and Three Forks Shale plays in the Williston Basin area of North Dakota.
Response to Low Oil Prices
In 2016 our industry continued to face a challenging commodity price environment leading to further reductions in capital investment compared with 2015. Our realized crude oil selling prices, including hedging, were $39.20 per barrel in 2016 (2015: $47.85; 2014: $92.59). In response, we improved operating efficiency across our portfolio and reduced our E&P capital and exploratory expenditures during 2016 to $1.9 billion, a decrease of over 50% compared to the same period in 2015, which partially contributed to our lower 2016 oil and gas production levels.
In addition to improving our operating efficiency and reducing our capital and exploratory expenditures, we proactively took other steps in 2016 to preserve the strength of our balance sheet and improve liquidity, including issuing equity securities and executing a debt refinancing transaction. In February 2016, we issued 28,750,000 shares of common stock and depositary shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock, for total net proceeds of $1.6 billion. In the third quarter of 2016, we initiated a debt refinancing transaction by issuing $1 billion of 4.30% notes due in 2027 and $500 million of 5.80% notes due in 2047 with proceeds used primarily to purchase higher-coupon bonds and redeem near-term maturities. At December 31, 2016, we had $2.7 billion in cash and cash equivalents and total liquidity including available committed credit facilities of approximately $7.3 billion.
We project our E&P capital and exploratory expenditures will be approximately $2.25 billion in 2017 as we plan to increase from two rigs to six rigs in the Bakken over the course of 2017. Capital expenditures for our Midstream operations are expected to be approximately $190 million. Oil and gas production in 2017 is forecast to be in the range of 300,000 boepd to 310,000 boepd excluding any contribution from Libya. As a result of reduced capital expenditures in 2016 and a high level of planned maintenance in the second quarter of 2017, we forecast our production to decline during the first half of 2017 and then increase in the third and fourth quarters of the year with the start-up of North Malay Basin and a new well at the Penn State Field in the Gulf of Mexico expected in the third quarter and production increases as a result of the rig ramp up in the Bakken.
In 2016, we realized a net operating cash flow deficit (cash flow from operating activities less cash flows from investing activities) of $1,295 million. Forward strip crude oil prices for 2017 are higher than average prices for 2016, and as a result, we forecast a smaller net operating cash flow deficit in 2017. We expect to fund our net operating cash flow deficit (including capital expenditures) for the full year of 2017 with cash on hand. Due to the low commodity price environment, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: reduce our planned capital program and other cash outlays, borrow from our committed credit facilities, issue debt or equity securities, and pursue asset sales.
Consolidated Results
Net loss attributable to Hess Corporation was $6,132 million in 2016 and $3,056 million in 2015. In 2014, net income attributable to Hess Corporation was $2,317 million. Excluding items affecting comparability summarized on page 27, the adjusted net loss was $1,489 million in 2016 and $1,113 million in 2015. Adjusted net income in 2014 was $1,308 million. Annual production averaged 322,000 boepd in 2016, 375,000 boepd in 2015, and 329,000 boepd in 2014. Total proved reserves were 1,109 million boe, 1,086 million boe, and 1,431 million boe at December 31, 2016, 2015, and 2014, respectively. Lower crude oil prices in 2015 resulted in negative revisions of 234 million boe at December 31, 2015, primarily related to proved undeveloped reserves.
Significant 2016 Activities
The following is an update of significant E&P activities during 2016:
Producing E&P assets:
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In North Dakota, net production from the Bakken oil shale play averaged 105,000 boepd (2015: 112,000 boepd), with the decrease from the prior-year period primarily due to reduced drilling activity in response to low oil prices. During 2016, we operated an average of 3.3 rigs, drilled 71 wells, completed 92 wells, and brought on production 100 wells, bringing the total operated production wells to 1,272 at December 31, 2016. Drilling and completion costs per operated well averaged $4.8 million in 2016, down 17% from 2015. In 2016, we also increased our standard well design to a 50-stage completion from the previous 35-stage completion. During 2017, we plan to increase our rig count to six rigs from two rigs, for an average of 3.5 rigs, to drill approximately 80 wells and bring approximately 75 wells on production. Net production for full year 2017 is forecast to be in the range of 95,000 boepd and 105,000 boepd. With the building rig count we expect our Bakken production in the fourth quarter of 2017 to average between 105,000 boepd and 110,000 boepd, which would represent a growth rate of approximately 15% from the first quarter to the fourth quarter.
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In the Gulf of Mexico, net production averaged 61,000 boepd (2015: 77,000 boepd). The decrease in production was the result of unplanned well downtime at the Tubular Bells Field (Hess 57%) due to subsurface valve failures in three wells, unplanned downtime at the Conger Field (Hess 38%) due to a failed subsurface valve in one well, and natural decline. Well workovers were conducted to replace the subsurface valves in the three wells at the Tubular Bells Field and in the well at the Conger Field, which caused an increase in workover expense for the year. In addition, we brought online a fifth production well and one water injection well at Tubular Bells during the year. In 2017, Gulf of Mexico production is forecast to average approximately 65,000 boepd.
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At the Valhall Field offshore Norway, net production averaged 28,000 boepd (2015: 33,000 boepd), with the decrease from the prior year primarily due to lower drilling activity, natural field decline and a planned shutdown. Net production from the Valhall Field is forecast to average between 25,000 boepd and 30,000 boepd in 2017. In 2017, the operator plans to drill two production wells from the existing platform rig, of which one well is expected to be completed in the fourth quarter. The operator plans to continue a multi-year well abandonment program.
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At Block A-18 of the JDA, the operator, Carigali Hess Operating Company, continued drilling production wells and completed commissioning of its booster compression project in the third quarter of 2016. Production averaged 206 mmcfd (2015: 255 mmcfd), including contribution from unitized acreage in Malaysia, with the decrease from prior-year primarily due to lower entitlement and downtime associated with commissioning of the new booster compression project. Production from the JDA is forecast to average approximately 210 mmcfd in 2017.
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In the North Malay Basin (NMB), net production from the Early Production System averaged 26 mmcfd (2015: 40 mmcfd). In 2016, we completed the installation of three remote wellhead platforms and the jacket of the central processing platform. We also achieved mechanical completion of the central processing platform topsides and transport to the field via a heavy lift vessel is planned for the first quarter of 2017. The full field development project is planned for completion in the third quarter of 2017, after which net production is expected to increase to 165 mmcfd.
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At the South Arne Field, offshore Denmark, we completed drilling of an eleven well multi-year program early in 2016. Net production averaged 13,000 boepd (2015: 13,000 boepd). In the fourth quarter, the Danish government awarded a 20 year extension to the South Arne Field license, extending expiry to 2047. Net production is forecast to average approximately 12,000 boepd in 2017.
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In the Utica shale, we drilled and completed 6 wells and brought 14 wells onto production before suspending drilling activities during the first quarter of 2016 in response to low commodity prices. Net production increased to 29,000 boepd in 2016 (2015: 24,000 boepd) and is expected to average between 15,000 boepd and 20,000 boepd in 2017.
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In Equatorial Guinea, net production was 33,000 boepd in 2016 down from 43,000 boepd in 2015 due to lower drilling activity and natural field decline. Net production in 2017 is expected to average approximately 25,000 boepd.
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In Libya, civil and political unrest has largely interrupted production and crude oil export capability in 2016. At the Waha fields (Hess 8%), the operator recommenced production in October 2016 following the lifting of force majeure by the national oil company of Libya. Net production from the Waha fields averaged 1,000 boepd for the year.
Other E&P assets:
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At the Hess operated Stampede development project (Hess 25%) in the Green Canyon area of the Gulf of Mexico, the topsides deck was installed on the hull and fabrication and pre-commissioning of topsides continue as planned. We also completed installation of subsea equipment at both drill centers in the field, drilled one development well, and commenced drilling on one water injector well. In 2017, we plan to install the tension leg platform and topsides, complete the sub-sea installation and continue our drilling operations with introduction of a second drilling rig. First production from the field is targeted for 2018, and is expected to ramp up to a net rate of approximately 15,000 boepd.
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In Guyana, at the offshore Stabroek Block (Hess 30%), the operator, Esso Exploration and Production Guyana Limited, completed a 3D seismic acquisition program covering approximately 17,000 square kilometers on the block and drilled two successful appraisal wells at the Liza discovery. The Liza-2 well was drilled to a total depth of 17,963 feet and encountered more than 190 feet of oil-bearing sandstone reservoirs in the Upper Cretaceous formations and included an extended drill stem test. The Liza-3 well was drilled to a total depth of 18,098 feet and encountered 210 feet of the same oil-bearing reservoirs encountered in other Liza wells. Pre-development planning and appraisal activities are underway and we expect to be in a position to sanction the first phase of the Liza development in mid-2017 with first production expected in 2020.
In 2016, the operator also drilled the Payara-1 exploration well at the Payara prospect, located approximately 10 miles northwest of the Liza discovery, and encountered more than 95 feet of oil-bearing sandstone reservoirs. At the Skipjack prospect 25 miles northwest of the Liza discovery, the operator completed the drilling of an exploration well, which was unsuccessful and expensed. In 2017, the operator plans to drill a well at the Snoek exploration prospect, a Liza-4 appraisal well, and a Payara-2 appraisal well. In addition, the operator will evaluate additional exploration opportunities on the broader Stabroek block.
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At the Equus project on Block WA-390-P in the offshore Carnarvon Basin of Australia, we were awarded a retention lease through 2021 covering certain areas within the WA-390-P License which include our Equus discoveries. In addition, we also completed drilling of an exploration commitment well at the WA-474-P License which is adjacent to Block WA-390-P. In the fourth quarter of 2016, we terminated a joint front-end engineering study with a third party natural gas liquefaction joint venture and notified the government of Australia of our intent to defer further development of the project. As a result, we recognized an after-tax charge of $693 million ($938 million pre-tax) to expense all previously capitalized exploratory well costs and other project related costs.
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In Ghana, we continued development planning and subsurface evaluation. The government of Côte d’Ivoire has challenged the maritime border between it and the country of Ghana, which includes a portion of our Deepwater Tano/Cape Three Points license. We are unable to proceed with development of this license until there is a resolution of this matter, which may also impact our ability to develop the license. The International Tribunal for Law of the Sea is expected to render a final ruling on the maritime border dispute in 2017. Under terms of our license and subject to resolution of the border dispute, we have declared commerciality for four discoveries, including the Pecan Field in March 2016, which would be the primary development hub for the block. We are continuing to work with the government on how best to progress work on the block given the maritime border dispute. See Capitalized Exploratory Well Costs in Note 4, Property, Plant and Equipment in the Notes to Consolidated Financial Statements.
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At the non-operated Sicily prospect, in the Keathley Canyon area of the deepwater Gulf of Mexico, where two exploration wells discovered hydrocarbons, we decided in 2016 not to pursue the project due to the low oil price environment and the limited time remaining on the leases. The costs of both wells were expensed in 2016.
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At the non-operated Melmar prospect in the Alaminos Canyon area of the deepwater Gulf of Mexico, the operator completed drilling of an exploration well in 2016, where noncommercial quantities of hydrocarbons were encountered and well costs were expensed.
The following is an update of significant Bakken Midstream activities during 2016:
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We continued to progress the construction of facilities and the reconfiguration of pipelines in McKenzie and Williams counties that are expected to increase throughput capacity for crude oil and natural gas originating from south of the Missouri River for transporting north to our natural gas processing and crude oil and natural gas liquids logistics assets in Tioga and Ramberg and multiple third-party pipelines.
Liquidity, and Capital and Exploratory Expenditures
Net cash provided by operating activities was $795 million in 2016 (2015: $1,981 million; 2014: $4,457 million). At December 31, 2016, cash and cash equivalents were $2,732 million (2015: $2,716 million) and total debt was $6,806 million (2015: $6,592 million). Our consolidated debt to capitalization ratio at December 31, 2016 was 30.4% (2015: 24.4%).
Capital and exploratory expenditures from continuing operations were as follows (in millions):
Exploration expenses charged to income included in E&P capital and exploratory expenditures above were:
(a)
In 2014, the above table excludes capital expenditures of $431 million related to our discontinued operations, and includes corporate capital expenditures of $53 million.
We plan to invest approximately $2.25 billion on E&P capital and exploratory expenditures and approximately $190 million in Midstream capital expenditures in 2017. Beginning January 1, 2017, Hess’s Midstream segment will include our interest in a Permian gas plant in West Texas and related CO2 assets, and water handling assets in North Dakota. These assets are wholly owned by the Corporation and are not included in our Hess Infrastructure Partners joint venture.
Consolidated Results of Operations
The after-tax income (loss) by major operating activity is summarized below:
(a)
Calculated as net income (loss) attributable to Hess Corporation less preferred stock dividends as applicable, divided by weighted average number of diluted shares.
The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income (loss) and affect comparability between periods. The items in the table below are explained on pages 32 through 36.
Items Affecting Comparability of Earnings Between Periods
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.
The following table reconciles reported net income (loss) attributable to Hess Corporation and adjusted net income (loss):
“Adjusted net income (loss)” presented in this report is a non-GAAP financial measure, which we define as reported net income (loss) attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods. Management uses adjusted net income (loss) to evaluate the Corporation’s operating performance and believes that investors’ understanding of our performance is enhanced by disclosing this measure, which excludes certain items that management believes are not directly related to ongoing operations and are not indicative of future business trends and operations. This measure is not, and should not be viewed as, a substitute for U.S. GAAP net income (loss).
Comparison of Results
Exploration and Production
Following is a summarized income statement of our E&P operations:
Excluding the E&P items affecting comparability of earnings between periods in the table on page 32, 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, Bakken Midstream tariffs, exploration expenses and income taxes, as discussed below.
Selling Prices: Average realized crude oil selling prices, including hedging, were 18% lower in 2016 compared to the prior year, primarily due to the declines in Brent and WTI crude oil prices. In addition, realized selling prices for natural gas liquids and natural gas declined in 2016 by 5% and 19%, respectively, compared to the prior year. In total, lower realized selling prices reduced 2016 financial results by approximately $440 million after income taxes compared with 2015. Our average selling prices were as follows:
Crude oil price hedging contracts increased E&P Sales and other operating revenues by $126 million ($79 million after income taxes) in 2015 and $193 million ($121 million after income taxes) in 2014. There were no crude oil hedge contracts in 2016.
Production Volumes: Our net daily worldwide production was as follows:
We expect total net production to average between 300,000 boepd and 310,000 boepd in 2017, excluding any contribution from Libya. Our production has been decreasing the last several quarters as a result of reducing our capital expenditures to manage in the lower price environment. We expect our production will continue to decline in the first half of 2017 as a result of this reduced spend and a high level of planned maintenance at four of our offshore assets in the second quarter. We forecast production to average between 290,000 boepd and 300,000 boepd in the first quarter and between 270,000 boepd and 280,000 boepd in the second quarter. Production is then forecast to increase in the third quarter with the start-up of North Malay Basin and a new well at the Penn State Field in the Gulf of Mexico to between 305,000 boepd and 315,000 boepd. We expect our production will continue to grow in the fourth quarter as Bakken production increases as a result of the rig ramp up and the first new Valhall well comes online. Fourth quarter production is forecast to average between 330,000 boepd and 340,000 boepd.
Production variances related to 2016, 2015 and 2014 can be summarized as follows:
United States: Onshore crude oil production was lower in 2016 compared to 2015, primarily due to reduced drilling activity in the Bakken shale play in response to low oil prices, while the increase in natural gas liquids production was primarily due to greater processed volumes at the Tioga gas plant. Onshore natural gas production was higher in 2016 compared to 2015, primarily due to a higher number of wells being on production in the Utica shale play relative to the prior year. Total offshore production was lower in 2016 compared to 2015, primarily due to subsurface valve failures in three wells at the Tubular Bells Field, a shut-in well to replace a subsurface valve at the Conger Field, extended planned shutdowns
on third-party hosted production facilities at the Tubular Bells and Conger Fields, and natural field decline. Onshore crude oil and natural gas liquids production was higher in 2015 compared to 2014, primarily due to continued drilling in the Bakken oil shale play, while the increase in natural gas production was primarily attributable to the Bakken and the Utica shale. Offshore production increased in 2015 relative to 2014 as higher production from the Tubular Bells Field, which came online in November 2014, was offset primarily by lower production from the Llano, Conger and Shenzi Fields.
Europe: Crude oil production was lower in 2016 compared to 2015, primarily due to lower drilling activity, natural field decline and a planned shutdown at the Valhall Field, offshore Norway. Crude oil and natural gas production was higher in 2015 compared to 2014, primarily due to less facility downtime and new wells at the Valhall Field in 2015.
Africa: Crude oil production in Africa was lower in 2016 compared to 2015, as a result of reduced drilling activity in Equatorial Guinea and the sale of our Algeria asset in the fourth quarter of 2015, where net production for 2015 amounted to 7,000 boepd. Crude oil production in Africa was lower in 2015 compared to 2014, due to Libyan production being shut-in. Force majeure declared by the national oil company of Libya was lifted in September 2016 and net production averaged 1,000 boepd in 2016.
Asia: Natural gas production was lower in 2016, compared to 2015, primarily due to the planned shutdown of production facilities at the JDA in 2016 to commission the booster compressor project and from lower production entitlement. Natural gas production was lower in 2015 compared to 2014 primarily due to asset sales partially offset by higher production at the JDA as a result of higher facility uptime.
Sales Volumes: The impact of lower sales volumes decreased after-tax results by approximately $540 million in 2016 compared to 2015. Our worldwide sales volumes were as follows:
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 our partners in Hess operated wells or other third-parties, as well as rail transportation fees from our Bakken Midstream operating segment. The decrease in Cost of products sold in 2016 compared to 2015, and in 2015 compared to 2014, principally reflects the decline in crude oil prices.
Cash Operating Costs: Cash operating costs, consisting of Operating costs and expenses, Production and severance taxes and E&P General and administrative expenses, decreased by $194 million in 2016 compared with the prior year (2015: $188 million decrease versus 2014). The decrease in 2016 compared to 2015 is due to lower production and ongoing cost reduction efforts, and lower production taxes in the Bakken. Operating costs in 2016 include higher workover costs to replace failed subsurface valves in the Gulf of Mexico. The decrease in 2015 compared to 2014 is due to cost reductions across the portfolio and lower production taxes in the Bakken, which were partially offset by higher operating costs at Tubular Bells where production commenced in the fourth quarter of 2014.
Bakken Midstream Tariffs Expense: Tariffs expense in 2016 increased versus 2015 primarily due to increased oil gathering tariffs and minimum volume deficiency payments related to rail export services in 2016, partially offset by lower gas volumes processed through the Tioga gas plant. Higher tariff expense in 2015 compared with 2014 primarily reflects higher volumes processed through the Tioga gas plant which was shut down during the first quarter of 2014 to complete a plant expansion and refurbishment project. For 2017, we estimate Midstream tariffs expense, which will include tariffs associated with our interests in a Permian gas plant in West Texas and related CO2 assets and water handling assets in North Dakota, to be in the range of $520 million to $550 million.
Depreciation, Depletion and Amortization: Depreciation, depletion and amortization (DD&A) costs decreased by $720 million in 2016 from 2015. The decrease resulted from lower production and an improved portfolio average DD&A rate due to the production mix. Higher production in 2015 from the Bakken, Tubular Bells and Utica fields, which had higher DD&A rates per barrel than the portfolio average, were the primarily drivers for the increase in DD&A costs in 2015 compared to 2014.
Unit costs: Unit cost per boe information is based on total E&P production volumes and exclude items affecting comparability of earnings as disclosed below. Actual and forecast unit costs are as follows:
(a)
Forecasted amounts assume no contribution from Libya.
Exploration Expenses: Exploration expenses, including items affecting comparability of earnings described below, were as follows:
Exploration expenses were higher in 2016 compared to 2015 primarily due to higher dry hole expense partially offset by lower leasehold impairment expense, geologic and seismic costs, and employee expenses. Exploration expenses were higher in 2015 compared to 2014 due to higher dry hole costs, partially offset by lower leasehold impairment expense, geologic and seismic costs, and employee expenses. See items affecting comparability of earnings between periods described below. For 2017, we estimate exploration expenses, excluding dry hole expense, to be in the range of $250 million to $270 million.
Income Taxes: The E&P income tax provision was an expense of $1,588 million in 2016, a benefit of $1,111 million in 2015 and an expense of $989 million in 2014. The income tax expense recognized in 2016, despite pre-tax losses, is the result of deferred income tax charges to establish valuation allowances on net deferred tax assets. Excluding the impact of these charges and other items affecting comparability of earnings between periods provided below and Libya, the effective income tax rates for E&P operations amounted to a benefit of 42% in 2016 (2015: 46% benefit; 2014: 37% charge). Based on current strip crude oil prices, we are forecasting a pre-tax loss for 2017. The E&P effective tax rate, excluding items affecting comparability of earnings between periods and Libyan operations, is expected to be a benefit in the range of 17% to 21%, which is lower than the comparable effective tax rate in 2016 due to our not recognizing a deferred tax benefit or expense commencing in 2017 in the U.S., Denmark (hydrocarbon tax only), and Malaysia until such time that deferred tax assets are re-established in these jurisdictions. See E&P items affecting comparability of earnings below and Critical Accounting Policies and Estimates - Income Taxes on page 42.
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:
The pre-tax amounts of E&P items affecting comparability of income (expense) are presented in the Statement of Consolidated Income as follows:
2016:
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Income taxes: We recorded a non-cash charge of $2,920 million to establish valuation allowances against net deferred tax assets as of December 31, 2016, as required under application of the accounting standards following a three-year cumulative loss. This deferred tax charge has no cash flow impact and the Corporation’s underlying tax position remains unchanged. In addition, we recorded a tax benefit of $51 million related to the resolution of certain international tax matters.
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Dry hole, lease impairment and other exploration expenses: We recorded a pre-tax charge of $938 million ($693 million after income taxes) to write-off all previously capitalized wells and other project related costs for our Equus natural gas project, offshore the North West Shelf of Australia, following the decision to defer further development of the project. In addition, we recorded a pre-tax charge of $83 million ($52 million after income taxes) to write-off the previously capitalized Sicily-1 exploration well based on our decision not to pursue the project.
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Offshore rig cost: We recognized a pre-tax charge of $105 million ($66 million after income taxes) related to an offshore drilling rig.
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Inventory write-off: We incurred a pre-tax charge of $39 million ($19 million after income taxes) to write off surplus materials and supplies inventory.
•
Exit costs and other: We recorded pre-tax exit and other costs of $26 million ($17 million after income taxes), which primarily relates to employee severance.
•
Gains on asset sale, net: We recognized a pre-tax gain of $27 million ($17 million after income taxes) related to the sale of undeveloped onshore acreage in the United States.
2015:
•
Impairment: We recorded noncash goodwill impairment charges totaling $1,483 million pre-tax ($1,483 million after income taxes), representing all goodwill of our E&P segment, due to the decline in crude oil prices. In addition, we recorded a pre-tax charge of $133 million ($83 million after income taxes) associated with our legacy conventional North Dakota assets.
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Dry hole, lease impairment and other exploration expenses: We recognized a pre-tax charge of $190 million ($86 million after income taxes) to write-off an exploration well, associated leasehold expenses and other costs related to the Dinarta Block in the Kurdistan Region of Iraq following the decision of the Corporation and its partner to relinquish the block and exit operations in the region. In offshore Ghana, we expensed previously capitalized well costs of $182 million ($117 million after income taxes) primarily associated with natural gas discoveries due to insufficient progress on appraisal negotiations with the regulator. In offshore Australia, we expensed previously capitalized well costs of $62 million ($45 million after income taxes) associated with discovered resources that we determined would not be included in the development concept for the Equus project. In addition, we recorded pre-tax charges totaling $84 million ($53 million after income taxes) primarily to impair exploration leases in the Gulf of Mexico.
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Exit costs and other: We recognized pre-tax charges totaling $21 million ($21 million after income taxes) associated with terminated international office space and incurred charges of $23 million ($16 million after income taxes) related to employee severance and other expenses.
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Inventory write-off: We incurred a pre-tax charge of $48 million ($30 million after income taxes) to write off
surplus drilling materials based on future drilling plans and recognized a pre-tax charge of $39 million ($28 million after income taxes) to reduce crude oil inventories to their net realizable value.
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Gains on asset sales, net: We completed the sale of approximately 13,000 acres of Utica dry gas acreage for consideration of approximately $120 million. This transaction resulted in a pre-tax gain of $49 million ($31 million after income taxes). We also completed the sale of our producing assets in Algeria in December 2015 and recognized a pre-tax loss of $21 million ($21 million after income taxes).
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Income taxes: In 2015, we recorded net tax benefits totaling $101 million, comprised primarily of $154 million to recognize a deferred tax benefit from a legal entity restructuring, $50 million benefit from receiving approval for an international investment incentive and a $112 million charge to recognize a partial valuation allowance against foreign deferred tax assets.
2014:
•
Gains on asset sales, net: We completed the sale of our producing assets in Thailand, 77,000 net acres of Utica dry gas acreage, including related wells and facilities, and an exploration asset in the United Kingdom North Sea. These divestitures generated total cash proceeds of $1,933 million and total pre-tax gains of $801 million ($774 million after income taxes). At the time of sale, these assets were producing at an aggregate net rate of approximately 19,000 boepd.
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Dry hole, lease impairment and other exploration expenses: We recorded dry hole and other exploration expenses for the write-off of a previously capitalized exploration well in the western half of Block 469 in the Gulf of Mexico of $169 million ($105 million after income taxes) and other charges totaling $135 million pre-tax ($68 million after income taxes) to write-off leasehold acreage in the Paris Basin of France, the Shakrok Block in Kurdistan and our interest in a natural gas exploration project, offshore Sabah, Malaysia.
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Exit costs and other: We recorded pre-tax severance and other exit costs of $28 million ($11 million after income taxes) resulting from our transformation to a more focused pure play E&P company.
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Income taxes: We recorded an income tax charge of $48 million for remeasurement of deferred taxes resulting from legal entity restructurings.
Bakken Midstream
Following is a summarized income statement of our Bakken Midstream operations:
(a)
The partnership is not subject to tax and, therefore, the noncontrolling interest’s share of net income is a pre-tax amount.
Total revenues and non-operating income in 2016 decreased from 2015, primarily as a result of lower rail export revenue associated with third-party rail charges, partially offset by recognition of deferred minimum volume deficiency payments earned. Total revenues and non-operating income in 2015 improved from 2014 mainly due to higher throughput volumes at the Tioga gas plant.
Operating costs and expenses were lower in 2016 compared to 2015 primarily due to a decrease in third-party rail charges. Operating costs and expenses were higher in 2015 compared to 2014 mainly due to an increase in third-party operating and maintenance expense. DD&A expenses were higher in 2016 compared to 2015, primarily due to capital expenditures on gathering pipelines and railcars that were placed in service. DD&A expenses were higher in 2015 compared with 2014, primarily due to a full year’s usage of the Tioga gas plant in 2015, which was shut down during the first quarter of 2014 in connection with a large-scale expansion, refurbishment and optimization project.
The increase in interest expense in 2016 and 2015 reflects borrowings by Hess Infrastructure Partners LP subsequent to its formation on July 1, 2015.
For 2017, we estimate net income attributable to Hess Corporation from the Midstream segment, excluding items affecting comparability of earnings between periods, to be in the range of $70 million to $90 million. In 2017, the Midstream segment will include our interests in a Permian gas plant in West Texas and related CO2 assets, and water handling assets in North Dakota in addition to assets that comprise our current Bakken Midstream segment.
Items Affecting Comparability of Earnings Between Periods: Bakken Midstream 2016 results included a pre-tax charge of $67 million ($21 million after income taxes and noncontrolling interest) to impair older specification rail cars.
Corporate, Interest and Other
The following table summarizes Corporate, Interest and Other expenses:
Corporate and other expenses, excluding items affecting comparability, were lower in 2016 compared to 2015, primarily due to reductions in employee costs, professional fees, and other general and administrative expenses, and the benefit of higher interest income and non-operating income. Corporate and other expenses for 2014 include a pre-tax gain of $13 million ($8 million after income taxes) related to the disposition of our 50% interest in a joint venture involved in the construction of an electric generating facility in Newark, New Jersey. Excluding the gain, 2015 costs are down compared to 2014 primarily due to lower employee costs and other expenses. In 2017 pre-tax corporate expenses, excluding items affecting comparability of earnings between periods, are estimated to be in the range of $140 million to $150 million.
Interest expense was comparable in 2016 compared to 2015, but capitalized interest expense increased over the same period with 2016 reflecting increased activity at the Hess operated Stampede development project. Interest expense was lower in 2015 compared to 2014, as lower interest rates offset higher average borrowings. Capitalized interest was also lower in 2015 compared to 2014 due to the cessation of capitalized interest on the Tubular Bells Field upon first production in the fourth quarter of 2014. In 2017 pre-tax interest expense, net is estimated to be in the range of $295 million to $305 million.
Items Affecting Comparability of Earnings Between Periods: Corporate, Interest and Other results included the following items affecting comparability of income (expense) before and after income taxes:
2016:
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Income tax: We recorded a non-cash charge of $829 million to establish valuation allowances against net deferred tax assets as of December 31, 2016, as required under application of the accounting standards following a three-year cumulative loss. This deferred tax charge has no cash flow impact and the Corporation’s underlying tax position remains unchanged.
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Loss on debt extinguishment: We recorded a pre-tax charge of $148 million ($92 million after income taxes) related to the repurchase and redemption of notes to complete a debt refinancing. See Note 12, Debt, in the Notes to Consolidated Financial Statements.
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Exit costs and other: We recorded pre-tax exit and other costs of $3 million ($2 million after income taxes), which primarily relates to employee severance.
2015:
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HOVENSA LLC: We recorded a pre-tax charge of $76 million ($49 million after income taxes) associated with debtor-in-possession financing provided to HOVENSA LLC and the estimated liability resulting from its bankruptcy resolution.
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Other: We recorded a pre-tax gain of $20 million ($13 million after income taxes) from the sale of land and incurred exit costs of $6 million pre-tax ($4 million after income taxes).
2014:
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Impairment: We recorded a pre-tax charge of $84 million ($52 million after income taxes) to reduce the carrying value of our equity investment in the Bayonne Energy Center to fair value.
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Other: We incurred severance charges of $19 million pre-tax ($12 million after income taxes) and exit related costs of $15 million pre-tax ($10 million after income taxes).
Discontinued Operations - Items Affecting Comparability of Earnings Between Periods
Discontinued operations attributable to Hess Corporation incurred a net loss of $48 million in 2015 compared to a net income of $625 million in 2014. Discontinued operations included ownership of an energy trading partnership through February 2015 and retail marketing through September 2014.
In September 2014, we completed the sale of our retail business for cash proceeds of approximately $2.8 billion. This transaction resulted in a pre-tax gain of $954 million ($602 million after income taxes). During 2014, we recorded pre-tax gains of $275 million ($171 million after income taxes) relating to the liquidation of last-in, first-out (LIFO) inventories associated with the divested downstream operations. In addition, we recorded pre-tax charges totaling $308 million ($202 million after income taxes) in 2014 for impairments, environmental matters, severance and exit related activities associated with the divestiture of downstream operations. We also recognized in 2014 a pre-tax charge of $115 million ($72 million after income taxes) related to the termination of lease contracts and the purchase of 180 retail gasoline stations in preparation for the sale of the retail operations.
Liquidity and Capital Resources
The following table sets forth certain relevant measures of our liquidity and capital resources at December 31:
(a)
Includes $733 million of debt outstanding from our Bakken Midstream joint venture at December 31, 2016 (2015: $704 million) that is non-recourse to Hess Corporation.
(b)
Total debt as a percentage of the sum of total debt plus equity.
Cash Flows
The following table sets forth a summary of our cash flows:
Operating Activities: Net cash provided by operating activities was $795 million in 2016, $1,981 million in 2015 and $4,457 million in 2014, primarily reflecting declining benchmark crude oil prices and changes in production volumes.
Investing Activities: The decrease in Additions to property, plant and equipment in 2016, as compared to 2015, is primarily due to reduced drilling activity (Bakken, Utica, Norway, Denmark and Equatorial Guinea) and reduced development expenditures (Tubular Bells, North Malay Basin and the JDA). The decrease in Additions to property, plant and equipment in 2015, as compared to 2014, is primarily due to reduced drilling activity (Bakken, Utica, Norway and Equatorial Guinea), reduced development expenditures at Tubular Bells and the JDA, and lower exploratory drilling activity (Ghana and Kurdistan). These reductions were offset by 2015 activity related to development activities at Stampede in the Gulf of Mexico and exploration drilling activity in the Gulf of Mexico and Guyana, and full field development at North Malay Basin.
Total proceeds from the sale of assets related to continuing operations amounted to $140 million in 2016 (2015: $50 million; 2014: $2,978 million). In 2014, we completed asset sales of our dry gas acreage in the Utica shale play, our assets in Thailand, the Pangkah Field, offshore Indonesia, and our interests in two power plant joint ventures. In 2014, net cash provided by investing activities from discontinued operations included proceeds of $2.8 billion from the sale of the retail business. In addition, we acquired our partners’ 56% interest in WilcoHess, a retail gasoline joint venture, for approximately $290 million and we incurred capital expenditures of $105 million related to the acquisition of previously leased retail gasoline stations.
Financing Activities: In 2016, total borrowings were $1.54 billion and total repayments of debt were $1.46 billion. In the first quarter of 2016, we issued 28,750,000 shares of common stock and depositary shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock for total net proceeds of $1.64 billion. In 2015, we received net cash consideration of approximately $2.6 billion from the sale of a 50% interest in our Bakken Midstream business. Upon formation of the joint venture, HIP issued $600 million of debt under a Term Loan A facility. The proceeds from the debt were distributed equally to the partners. We purchased common stock under our $6.5 billion Board authorized stock repurchase plan of $142 million in 2015 and $3,715 million in 2014. Common and preferred stock dividends paid were $350 million in 2016 (2015: $287 million; 2014: $303 million).
Future Capital Requirements and Resources
At December 31, 2016, we had $2.7 billion in cash and cash equivalents and total liquidity, including available committed credit facilities, of approximately $7.3 billion. Cash and cash equivalents held outside of the U.S., which we have the ability to repatriate without triggering a U.S. cash tax liability, amounted to $287 million at December 31, 2016.
Net production in 2017 is forecast to be in the range of 300,000 boepd to 310,000 boepd, excluding any contribution from Libya and we expect our 2017 E&P capital and exploratory expenditures will be approximately $2.25 billion. Based on current forward strip crude oil prices for 2017, which are higher than 2016 prices, we forecast a smaller net loss and net operating cash flow deficit (including capital expenditures) in 2017 compared to 2016. We expect to fund our projected net operating cash flow deficit (including capital expenditures) through 2017 with cash on hand. Due to the low commodity price environment, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: further reduce our planned capital program and other cash outlays, borrow from our committed credit facilities, issue debt or equity securities, and pursue asset sales.
The table below summarizes the capacity, usage, and available capacity of our borrowing and letter of credit facilities at December 31, 2016:
(a)
This credit facility may only be utilized by HIP and is non-recourse to Hess Corporation.
(b)
Committed and uncommitted lines have expiration dates through 2018.
Hess Corporation has a $4.0 billion syndicated revolving credit facility expiring in January 2020. Borrowings on the facility will generally bear interest at 1.3% above the London Interbank Offered Rate (LIBOR). The interest rate will be higher if our credit rating is lowered. The facility contains a financial covenant that limits the amount of the total borrowings on the last day of each fiscal quarter to 65% of the Corporation’s total capitalization, defined as total debt plus stockholders’ equity. As of December 31, 2016, Hess Corporation had no outstanding borrowings under this facility and was in compliance with this financial covenant.
We had $188 million in letters of credit outstanding at December 31, 2016 (2015: $113 million), which primarily relate to our international operations. See also Note 24, Financial Risk Management Activities in the Notes to Consolidated Financial Statements.
HIP has a $400 million 5-year syndicated revolving credit facility, which can be used for borrowings and letters of credit to fund the joint venture’s operating activities and capital expenditures. Borrowings generally bear interest at the LIBOR plus an applicable margin ranging from 1.10% to 1.70%. The interest rate is subject to adjustment based on HIP’s leverage ratio, which is calculated as total debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). If HIP obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to time. The credit facility contains financial covenants that generally require a leverage ratio of no more than 5.0 to 1.0 for the prior four fiscal quarters and an interest coverage ratio, which is calculated as EBITDA to interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters. HIP is in compliance with these financial covenants at December 31, 2016.
At December 31, 2016, borrowings under HIP’s revolving credit facility, which are non-recourse to Hess Corporation, amounted to $153 million. HIP also has a five-year Term Loan A loan facility with outstanding borrowings of $585 million, excluding deferred issuance costs, which is also non-recourse to Hess Corporation.
We also have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred stock.
Credit Ratings
Two of the three major credit rating agencies that rate our debt have assigned an investment grade rating. In February 2016, Standard and Poor’s Ratings Services (S&P) lowered our investment grade credit rating one notch to BBB- with stable outlook and Moody’s Investors Service (Moody’s) lowered our credit rating to Ba1 with stable outlook, which is below investment grade. In December 2016, Fitch Ratings (Fitch) lowered our investment grade credit rating one notch to BBB- with stable outlook. In February 2017, S&P re-affirmed our investment grade credit rating of BBB- with stable outlook. The consequence of lower credit ratings is an increase in interest rates and facility fees on our credit facilities and the potential for additional required collateral under operating agreements. As of December 31, 2016, based on our current credit ratings, we may be required to issue additional collateral in the form of letters of credit up to approximately $270 million. If Fitch or S&P were to reduce their rating on our unsecured debt below investment grade, we estimate that we could be required to issue additional letters of credit up to $200 million as of December 31, 2016.
Contractual Obligations and Contingencies
The following table shows aggregate information about certain contractual obligations at December 31, 2016:
(a)
We anticipate cash payments for interest of $397 million for 2017, $760 million for 2018-2019, $670 million for 2020-2021, and $4,514 million thereafter for a total of $6,341 million.
Capital expenditures represent amounts that were contractually committed at December 31, 2016, including the portion of our planned capital expenditure program for 2017. Obligations for operating expenses include commitments for oil and gas production expenses, seismic purchases and other normal business expenses. Other liabilities reflect contractually committed obligations in the Consolidated Balance Sheet at December 31, 2016, including pension plan liabilities and estimates for uncertain income tax positions.
The Corporation and certain of its subsidiaries, lease drilling rigs, office space and other assets for varying periods under leases accounted for as operating leases.
Off-Balance Sheet Arrangements
At December 31, 2016, we have $27 million in letters of credit for which we are contingently liable. See also Note 21, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
Foreign Operations
We conduct exploration and production activities outside the U.S., principally in Europe (Norway and Denmark), Africa (Equatorial Guinea, Libya, and Ghana), Asia (Joint Development Area of Malaysia/Thailand and Malaysia), Australia, South America (Guyana and Suriname) and Canada. Therefore, we are subject to the risks associated with foreign operations, including political risk, corruption, acts of terrorism, tax law changes and currency risk. See Item 1A. Risk Factors for further details.
Critical Accounting Policies and Estimates
Accounting policies and estimates affect the recognition of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income. The accounting methods used can affect net income, equity and various financial statement ratios. However, our accounting policies generally do not change cash flows or liquidity.
Accounting for 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 drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. In production operations, costs of injected CO2 for tertiary recovery are expensed as incurred.
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves, and the economic and operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.
Crude Oil and Natural Gas Reserves: The determination of estimated proved reserves is a significant element in arriving at the results of operations of exploration and production activities. The estimates of proved reserves affect well capitalizations, the unit of production depreciation rates of proved properties and wells and equipment, as well as impairment testing of oil and gas assets and goodwill.
For reserves to be booked as proved they must be determined with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. In addition, government and project operator approvals must be obtained and, depending on the amount of the project cost, senior management or the Board of Directors must commit to fund the project. We maintain our own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties. Our technical staff updates reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management review. We also engage an independent third-party consulting firm to audit approximately 80% of our total proved reserves each year.
Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions. As discussed in Item 1A. Risk Factors, crude oil prices are volatile which can have an impact on our proved reserves. For example, the average WTI crude oil price used in the determination of proved reserves at December 31, 2016, 2015, and 2014 was $42.68, $50.13, and $94.42 per barrel, respectively. The lower prices for 2016 and 2015 relative to 2014 resulted in negative revisions to our proved reserves at December 31, 2016 of 29 million boe (2015: 234 million boe). If crude oil prices in 2017 are at levels below that used in determining 2016 proved reserves, we may recognize further negative revisions to our December 31, 2016 proved undeveloped reserves. In addition, we may recognize negative revisions to proved developed reserves, which can vary significantly by asset due to differing operating cost structures. Conversely, price increases in 2017 above those used in determining 2016 proved reserves could result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2017. It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves as of December 31, 2017, due to a number of factors that are currently unknown, including 2017 crude oil prices, any revisions based on 2017 reservoir performance, and the levels to which industry costs will change in response to movements in commodity prices. A 10% change in proved developed and proved undeveloped reserves at December 31, 2016 would result in an approximate $300 million pre-tax change in depreciation, depletion, and amortization expense for 2017. See the Supplementary Oil and Gas Data on pages 84 through 94 in the accompanying financial statements for additional information on our oil and gas reserves.
Bakken Midstream Joint Venture: On July 1, 2015, we sold a 50% interest in HIP to GIP for net cash consideration of approximately $2.6 billion. We consolidate the activities of HIP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles. We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power through our 50% ownership to direct those activities that most significantly impact the economic performance of HIP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to HIP. This conclusion was based on a qualitative analysis that considered HIP’s
governance structure, the commercial agreements between HIP and us, and the voting rights established between the members which provide us the ability to control the operations of HIP.
Impairment of Long-lived Assets: We review long-lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long-lived assets are tested based on identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is determined 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 present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of historical twelve-month average prices.
Our impairment tests of long-lived E&P producing assets are based on our best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each time an impairment test is performed. We could have impairments if the projected production volumes from oil and gas fields decrease, crude oil and natural gas selling prices decline significantly for an extended period or future estimated capital and operating costs increase significantly. As a result of the extended period of low crude oil prices, we tested our oil and gas properties for impairment. See Note 6, Impairment in the Notes to Consolidated Financial Statements.
Impairment of Goodwill: Goodwill is tested for impairment annually on October 1st or when events or circumstances indicate that the carrying amount of the goodwill may not be recoverable based on a two-step process. The goodwill test is conducted at a reporting unit level, which is defined in accounting standards as an operating segment or one level below an operating segment. The reporting unit or units to be used in an evaluation and measurement of goodwill for impairment testing are determined from a number of factors, including the manner in which the business is managed. Prior to the second quarter of 2015, we had one operating segment, E&P consisting of two reporting units, Offshore and Onshore which reflected the manner in which performance was assessed by the Operating segment manager. In the second quarter of 2015 we established a second operating segment, Bakken Midstream, which previously was part of the Onshore reporting unit. Prior to the formation of the Bakken Midstream operating segment the Offshore reporting unit had allocated goodwill of $1,098 million while the Onshore reporting unit had allocated goodwill of $760 million. Upon formation of the Bakken Midstream operating segment, we allocated $375 million of goodwill from the Onshore reporting unit to the Bakken Midstream operating segment based on the relative fair values of the Bakken Midstream business and the remainder of the Onshore reporting unit. There was no change to the composition of the Offshore reporting unit.
In step one of the impairment test, the fair value of a reporting unit is compared with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying value, goodwill is not impaired. If the carrying value of the reporting unit exceeds its fair value, we perform step two to determine possible impairment by comparing the implied fair value of goodwill with the carrying amount. The implied fair value of goodwill is determined by assuming the reporting unit is purchased at fair value with assets and liabilities of the reporting unit being reflected at fair value in the same manner as the accounting prescribed for a business combination. The resulting excess of fair value of the reporting unit over the amounts assigned to the reporting unit’s assets and liabilities represents the implied fair value of goodwill. If the implied fair value of goodwill is less than its carrying amount, an impairment loss would be recorded.
Our fair value estimate of each reporting unit is the sum of the anticipated discounted cash flows of producing assets and known development projects and an estimated market premium to reflect the market price an acquirer would pay for potential synergies including cost savings, access to new business opportunities, enterprise control and increased market share. The determination of the fair value of each reporting unit depends on estimates about oil and gas reserves, future prices, timing of future net cash flows and market premiums. We also consider the relative market valuation of similar peer companies, and other market data if available, in determining fair value of a reporting unit. In addition, a qualitative reconciliation of our market capitalization to the fair value of the reporting units used in the goodwill impairment test is performed as of the testing date to assess reasonableness of the reporting unit fair values.
Significant extended declines in crude oil and natural gas prices or reduced reserve estimates could lead to a decrease in the fair value of a reporting unit that could result in failing step one and potentially result in an impairment of goodwill based on the outcome of step two. If a reporting unit fails step one, it is possible that the implied fair value of goodwill in step two exceeds its carrying value due to one or more assets of the reporting unit having a fair value below its carrying value.
As there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing, there may be impairments of individual assets that would not cause an impairment of the goodwill assigned at the reporting unit level or there could be an impairment of goodwill without a corresponding impairment of an underlying asset.
In the second quarter of 2015, we performed impairment tests on the Offshore and Onshore reporting units in accordance with accounting standards for goodwill immediately prior to creation of the Bakken Midstream operating segment. No impairment resulted from this assessment. In addition, accounting standards require that following a reorganization, allocated goodwill should be tested for impairment. We also performed impairment tests on the allocated goodwill for the Bakken Midstream and the Onshore reporting unit at June 30, 2015. Goodwill allocated to the Bakken Midstream operating segment passed the impairment test but the goodwill allocated to the Onshore reporting unit did not pass the impairment test. As a result, we recorded a noncash pre-tax charge of $385 million ($385 million after income taxes) in the second quarter of 2015 to reflect the Onshore reporting unit’s goodwill at its implied fair value of zero based on a hypothetical purchase price allocation as stipulated in the accounting standards.
As a result of the decline in crude oil prices in the fourth quarter of 2015, we performed an impairment test at December 31, 2015 on the Offshore reporting unit and determined its goodwill was impaired. We recorded a pre-tax impairment charge of $1,098 million ($1,098 million after income taxes) to reflect the Offshore reporting unit’s goodwill at its implied fair value of zero based on a hypothetical purchase price allocation as stipulated in the accounting standards.
Effective January 1, 2017, as part of a reorganization of our E&P business, the Onshore and Offshore reporting units were combined within the E&P operating segment, which had no goodwill at December 31, 2016. This reorganization had no impact on the composition of the Bakken Midstream operating segment. We expect that the benefits of our remaining goodwill totaling $375 million assigned to the Bakken Midstream operating segment will be recovered based on market conditions at December 31, 2016.
Income Taxes: Judgments are required in the determination and recognition of income tax assets and liabilities in the financial statements. These judgments include the requirement to only recognize the financial statement effect of a tax position when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination.
We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recorded deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized.
The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves, selling prices, and other subjective operating assumptions that are consistent with internal business forecasts. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and carryback or carryforward periods that are so brief that it would limit realization of tax benefits if a significant deductible temporary difference is expected to reverse in a single year. Due to a sustained low commodity price environment we experienced a three-year cumulative consolidated loss as of December 31, 2016. A three-year cumulative consolidated loss constitutes objective negative evidence to which the accounting standards require we assign significant weight relative to subjective evidence such as our estimates of future taxable income.
As of December 31, 2016, the Consolidated Balance Sheet reflects a $5,450 million valuation allowance against the net deferred tax assets for multiple jurisdictions based on the evaluation of the accounting standards described above, with $3,749 million recorded in the fourth quarter of 2016 related primarily to the U.S., Denmark (hydrocarbon tax only), and Malaysia. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income change or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as expected future growth. We do not provide for deferred U.S. income taxes for that portion of undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations.
Asset Retirement Obligations: We have material legal obligations to remove and dismantle long-lived assets and to restore land or seabed at certain exploration and production locations. In accordance with generally accepted accounting principles, we recognize a liability for the fair value of required asset retirement obligations. In addition, the fair value of any
legally required conditional asset retirement obligation is recorded if the liability can be reasonably estimated. We capitalize such costs as a component of the carrying amount of the underlying assets in the period in which the liability is incurred. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. In order to measure these obligations, we estimate the fair value of the obligations by discounting the future payments that will be required to satisfy the obligations. In determining these estimates, we are required to make several assumptions and judgments related to the scope of dismantlement, timing of settlement, interpretation of legal requirements, inflationary factors and discount rate. In addition, there are other external factors which could significantly affect the ultimate settlement costs for these obligations including changes in environmental regulations and other statutory requirements, fluctuations in industry costs and foreign currency exchange rates and advances in technology. As a result, our estimates of asset retirement obligations are subject to revision due to the factors described above. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values.
Retirement Plans: We have funded non-contributory defined benefit pension plans, an unfunded supplemental pension plan and an unfunded postretirement medical plan. We recognize the net change in the funded status of the projected benefit obligation for these plans in the Consolidated Balance Sheet.
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; the rate of future increases in compensation levels, and participant mortality assumptions. These assumptions represent estimates made by us, some of which can be affected by external factors. For example, the discount rate used to estimate our projected benefit obligation is based on a portfolio of high-quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations, while the expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category. Changes in these assumptions can have a material impact on the amounts reported in our financial statements.
Derivatives: We utilize derivative instruments, including futures, forwards, options and swaps, individually or in combination to mitigate our exposure to fluctuations in the prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates.
All derivative instruments are recorded at fair value in our Consolidated Balance Sheet. Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges) or hedges of firm commitments (fair value hedges). The effective portion of changes in fair value of derivatives that are designated as cash flow hedges is recorded as a component of other comprehensive income (loss). Amounts included in Accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of derivatives designated as cash flow hedges is recorded currently in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and our credit is considered for accrued liabilities.
We also record certain nonfinancial assets and liabilities at fair value when required by generally accepted accounting principles. These fair value measurements are recorded in connection with business combinations, qualifying non-monetary exchanges, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments or goodwill.
We determine 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), including discounted cash flows and other unobservable data. 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. 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.
Environment, Health and Safety
Our long term vision and values provide a foundation for how we do business and define our commitment to meeting high standards of corporate citizenship and creating a long lasting positive impact on the communities where we do business. Our strategy is reflected in our environment, health, safety and social responsibility (EHS & SR) policies and by a management system framework that helps protect our workforce, customers and local communities. Our management systems are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance. Improved performance may, in the short-term, increase our operating costs and could also require increased capital expenditures to reduce potential risks to assets, reputation and license to operate. In addition to enhanced EHS & SR performance, improved productivity and operational efficiencies may be realized from investments in EHS & SR. We have programs in place to evaluate regulatory compliance, audit facilities, train employees, prevent and manage risks and emergencies and to generally meet corporate EHS & SR goals and objectives.
We recognize that climate change is a global environmental concern. We assess, monitor and take measures to reduce our carbon footprint at existing and planned operations. We are committed to complying with all Greenhouse Gas (GHG) emissions mandates and the responsible management of GHG emissions at our facilities.
We will have continuing expenditures for environmental assessment and remediation. Sites where corrective action may be necessary include onshore exploration and production facilities, sites from discontinued operations as to which we retained liability and, although not currently significant, “Superfund” sites where we have been named a potentially responsible party.
We accrue for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable. At December 31, 2016, our reserve for estimated remediation liabilities was approximately $80 million. We expect that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. Our remediation spending was approximately $10 million in 2016 (2015: $13 million; 2014: $12 million). The level of other expenditures to comply with federal, state, local and foreign country environmental regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As discussed in Note 24, Financial Risk Management Activities, in the Notes to Consolidated Financial Statements, in the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural gas as well as changes in interest rates and foreign currency values. In the disclosures that follow, financial risk management activities refer to the mitigation of these risks through hedging activities.
Controls: We maintain a control environment under the direction of our Chief Risk Officer. Controls over instruments used in financial risk management activities include volumetric and term limits. Our Treasury department is responsible for administering and monitoring foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors.
Instruments: We primarily use forward commodity contracts, foreign exchange forward contracts, futures, swaps, and options to affect risk management activities. These contracts are generally widely traded instruments with standardized terms. The following describes these instruments and how we use them:
•
Swaps: We use financially settled swap contracts with third-parties as part of our financial risk management 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.
•
Forward Foreign Exchange Contracts: We enter into forward contracts, primarily for the British Pound and Danish Krone which commit us to buy or sell a fixed amount of these currencies at a predetermined exchange rate on a future date.
•
Exchange Traded Contracts: We may use 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.
•
Options: Options on various underlying energy commodities include exchange traded and third-party contracts and have various exercise periods. As a seller of options, we receive a premium at the outset and bear the risk of unfavorable changes in the price of the commodity underlying the option. As a purchaser of options, we pay a premium at the outset and have the right to participate in the favorable price movements in the underlying commodities.
Financial Risk Management Activities
We have outstanding foreign exchange contracts with a total notional amount of $785 million at December 31, 2016 that are used to reduce our exposure to fluctuating foreign exchange rates for various currencies. The change in fair value of foreign exchange contracts from a 10% weakening of the U.S. Dollar exchange rate is estimated to be a loss of approximately $5 million at December 31, 2016.
At December 31, 2016, our outstanding long-term debt of $6,806 million, including current maturities, had a fair value of $7,548 million. A 15% increase or decrease in the rate of interest would decrease or increase the fair value of debt by approximately $510 million or $580 million, respectively.
We have no outstanding commodity price hedges at December 31, 2016.
Item 8. Financial Statements and Supplementary Data
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
Page
Number
Management’s Report on Internal Control over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheet at December 31, 2016, and 2015
Statement of Consolidated Income for each of the Three Years in the Period Ended December 31, 2016
Statement of Consolidated Comprehensive Income for each of the Three Years in the Period Ended December 31, 2016
Statement of Consolidated Cash Flows for each of the Three Years in the Period Ended December 31, 2016
Statement of Consolidated Equity for each of the Three Years in the Period Ended December 31, 2016
Notes to Consolidated Financial Statements
Nature of Operations, Basis of Presentation and Summary of Accounting Policies
Common and Preferred Stock Issuance
Inventories
Property, Plant and Equipment
Goodwill
Impairment
Bakken Midstream Joint Venture
Dispositions
Discontinued Operations
HOVENSA LLC
Asset Retirement Obligations
Debt
Share-based Compensation
Retirement Plans
Exit and Disposal Costs
Income Taxes
Outstanding and Weighted Average Common Shares
Share Repurchase Plan
Supplementary Cash Flow Information
Leased Assets
Guarantees, Contingencies and Commitments
Segment Information
Related Party Transactions
Financial Risk Management Activities
Supplementary Oil and Gas Data
Quarterly Financial Data
Schedule II*-Valuation and Qualifying Accounts
* 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 (2013 framework). Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2016.
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, 2016, 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 23, 2017
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, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 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, 2016, 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, 2016 and 2015, 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, 2016 of Hess Corporation and consolidated subsidiaries, and our report dated February 23, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
New York, New York
February 23, 2017
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
We have audited the accompanying consolidated balance sheets of Hess Corporation and consolidated subsidiaries (the “Corporation”) as of December 31, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 23, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
New York, New York
February 23, 2017
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 Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
See accompanying Notes to 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Operations, Basis of Presentation and Summary of Accounting Policies
Unless the context indicates otherwise, references to “Hess”, “the Corporation”, “Registrant”, “we”, “us” and “our” refer to the consolidated business operations of Hess Corporation and its affiliates.
Nature of Business: Hess Corporation is a global Exploration and Production (E&P) company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Denmark, Equatorial Guinea, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Norway. The Bakken Midstream operating segment, which was established in the second quarter of 2015, provides fee-based services, including gathering, compressing and processing natural gas and fractionating natural gas liquids, or NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; and storing and terminaling propane, primarily in the Bakken and Three Forks Shale plays in the Williston Basin area of North Dakota.
Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest. We also consolidate Hess Infrastructure Partners LP (HIP), a variable interest entity, based on our conclusion that we have the power through our 50% ownership to direct those activities that most significantly impact the economic performance of HIP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to HIP. Our undivided interests in unincorporated oil and gas exploration and production ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method.
In 2016, we adopted Accounting Standard Update (ASU) 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs to be presented in the balance sheet as a direct reduction to the associated debt liability. The Consolidated Balance Sheet at December 31, 2015 has been recast to reduce Other assets and Long-term debt by $38 million.
In 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. This ASU requires that management evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the financial statements are issued. This ASU is effective for us beginning in the fourth quarter of 2016. The adoption of ASU 2014-15 did not have an impact on our consolidated financial statements.
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 E&P segment recognizes revenue from the sale of crude oil, natural gas liquids, and natural gas, when title passes to the customer. Differences between E&P natural gas volumes sold and our entitlement share of natural gas production are not material.
In our E&P activities, we engage 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. These arrangements are reported net in Sales and other operating revenues in the Statement of Consolidated Income.
Our Bakken Midstream segment recognizes revenue from fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, terminaling and loading crude oil and natural gas liquids, transportation of crude oil by rail car and the storage and terminaling of propane when pervasive evidence of an arrangement exists, delivery has occurred or services rendered, price is fixed or determinable, and collectability is reasonably assured.
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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 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: We record 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 facilities 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.
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: We review long-lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is determined 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 present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a projected amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of historical twelve-month average prices. As a result of the prevailing low crude oil price environment, we tested our oil and gas properties for impairment. See Note 6, Impairment.
Impairment of Goodwill: Goodwill is tested for impairment annually on October 1st or when events or circumstances indicate that the carrying amount of the goodwill may not be recoverable based on a two-step process. In step one of the impairment test, the fair value of a reporting unit is compared with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying value, goodwill is not impaired. If the carrying value of the reporting unit exceeds its fair value, we perform step two to determine possible impairment by comparing the implied fair value of goodwill with the carrying amount. If the implied fair value of goodwill is less than its carrying amount, an impairment loss would be recorded. In addition to our annual test, we also performed separate goodwill impairment tests at December 31, 2015 and June 30, 2015. See Note 6, Impairment.
Cash and Cash Equivalents: Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have maturities of three months or less when acquired.
Inventories: Inventories are valued at the lower of cost or market. Cost is generally determined using average actual costs.
Income Taxes: Deferred income taxes are determined using the liability method. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recorded deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If,
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when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized. The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and carryback or carryforward periods that are so brief that it would limit realization of tax benefits if a significant deductible temporary difference is expected to reverse in a single year. We assign cumulative historical losses significant weight in the evaluation of realizability relative to more subjective evidence such as forecasts of future income. In addition, we recognize 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. We do not provide for deferred U.S. income taxes for that portion of undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations. We classify interest and penalties associated with uncertain tax positions as income tax expense.
Asset Retirement Obligations: We have material legal obligations to remove and dismantle long-lived assets and to restore land or the seabed at certain exploration and production locations. We initially recognize a liability for the fair value of legally required asset retirement obligations in the period in which the retirement obligations are incurred, and capitalize the associated asset retirement costs as part of the carrying amount of the long-lived assets. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. Fair value is determined by applying a credit adjusted risk-free rate to the undiscounted expected future abandonment expenditures, which represent Level 3 inputs in the fair value hierarchy defined under Fair Value Measurements below.
Retirement Plans: We recognize 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. We recognize the net changes in the funded status of these plans in the year in which such changes occur. 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 or the remaining average expected life if a plan’s participants are predominantly inactive.
Derivatives: We utilize derivative instruments for financial risk management activities. In these activities, we may use futures, forwards, options and swaps, individually or in combination, to mitigate our exposure to fluctuations in prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates.
All derivative instruments are recorded at fair value in our Consolidated Balance Sheet. Our 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: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and our credit is considered for accrued liabilities. We also record 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. We determine 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), including discounted cash flows and other unobservable data. 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.
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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.
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.
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. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3.
Netting of Financial Instruments: We generally enter 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 our intent and practice is to offset amounts in the case of such a termination, our policy is to record the fair value of derivative assets and liabilities on a net basis. In the normal course of business, we rely 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 us, “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. We are 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.
Share-based Compensation: We account for share-based compensation under the fair value method of accounting. 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. We estimate 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 remeasuring monetary assets and liabilities that are denominated in a currency other than 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, primarily those in Norway where the Norwegian Krone is used, adjustments resulting from translating foreign currency assets and liabilities into U.S. Dollars are recorded in the Consolidated Balance Sheet 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: We accrue and expense the undiscounted environmental costs necessary to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. At year-end 2016, our reserve for estimated remediation liabilities was approximately $80 million. Environmental expenditures that increase the life or efficiency of property or reduce or prevent future adverse impacts to the environment are capitalized.
New Accounting Pronouncements: In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09, Revenue from Contracts with Customers, as a new Accounting Standards Codification (ASC) Topic, ASC 606. This ASU is effective for us beginning in the first quarter of 2018, with early adoption permitted from the first quarter of 2017. We have developed a project plan for the implementation of ASC 606 in the first quarter of 2018, and conducted an evaluation of a sample of revenue contracts with customers against the requirements of the standard. Further analysis is planned in 2017 to complete the implementation plan. Based on our assessment to date, we have not identified any changes
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to the timing of revenue recognition based on the requirements of ASC 606 that would have a material impact on our consolidated financial statements. We plan to adopt ASC 606 using the modified retrospective method that requires application of the new standard prospectively from the date of adoption with a cumulative effect adjustment recorded to retained earnings as of January 1, 2018.
In February 2016, the FASB issued ASU 2016-02, Leases, as a new ASC Topic, ASC 842. The new standard will require assets and liabilities to be reported on the balance sheet for all leases with lease terms greater than one year, including leases currently treated as operating leases under the existing standard. This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted. We are currently assessing the impact of the ASU on our consolidated financial statements.
In March 2016, the FASB issued Accounting Standards Update (ASU) 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU makes changes to various provisions associated with share-based accounting, including provisions affecting the accounting for income taxes, the accounting for forfeitures, and the consideration of net settlement provisions on the balance sheet classification of the share-based award. This ASU is effective for us beginning in the first quarter of 2017. The adoption of ASU 2016 - 09 is not expected to have a material impact on our consolidated financial statements.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model. This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted from the first quarter of 2019. We are currently assessing the impact of the ASU on our consolidated financial statements.
In October 2016, the FASB issued ASU 2016-16, Income Taxes - Intra-Entity Transfer of Assets Other than Inventory. This ASU will require the recognition of income tax consequences from intra-entity transfer of assets other than inventory when the transfer occurs. This ASU is effective for us beginning in the first quarter of 2018, with early adoption permitted. We plan to adopt ASU 2016-16 in the first quarter of 2017, which is not expected to have a material impact on our consolidated financial statements.
In January 2017, the FASB issued ASU 2017-01, Business Combinations - Clarifying the Definition of a Business. This ASU provides a screen that excludes an integrated set of activities and assets from the definition of a business if the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets. This ASU also clarifies that an integrated set of activities and assets must include (at a minimum), an input and a substantive process that together significantly contribute to the ability to create output to be considered a business. This ASU is effective for us beginning in the first quarter of 2018, with early application permitted. We are currently assessing the impact of the ASU on our consolidated financial statements.
In January 2017, the FASB issued ASU 2017-04, Intangibles - Goodwill and Other - Simplifying the Test for Goodwill Impairment. This ASU modifies the concept of goodwill impairment from a condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of the reporting unit exceeds its fair value. Thus, an entity should recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value. The impairment charge would be limited by the amount of goodwill allocated to the reporting unit. This ASU removes the requirement to determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination. This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted. We are currently assessing the impact of the ASU on our consolidated financial statements.
2. Common and Preferred Stock Issuance
In February 2016, we issued 28,750,000 shares of common stock and depositary shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock (Convertible Preferred Stock), par value $1 per share, with a liquidation preference of $1,000 per share, for total net proceeds of approximately $1.6 billion after deducting underwriting discounts, commissions, and offering expenses. The dividends on the Convertible Preferred Stock will be payable on a cumulative basis. Unless converted earlier, each share of Convertible Preferred Stock will automatically convert into between 21.822 shares and 25.642 shares of our common stock based on the average share price over a period of twenty consecutive trading days ending prior to February 1, 2019 (the “Final Average Price”), subject to anti-dilution adjustments. See Note 17, Outstanding and Weighted Average Common Shares.
We also entered into capped call transactions that are expected generally to reduce the potential dilution to our common stock upon conversion of the Convertible Preferred Stock if the Final Average Price exceeds $45.83 per share, subject to anti-
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dilution adjustments. The number of common shares to be delivered by the counterparties to us will be the value of the capped call transactions at conversion divided by the Final Average Price. The value of the capped call transactions will be zero if the Final Average Price is $45.83 or less and can be up to the capped value of approximately $98 million if the Final Average Price is $53.625 or higher. For any Final Average Price between $45.83 and $53.625, the value of the capped call transactions will be 12.55 million covered shares multiplied by the difference between the Final Average Price and $45.83. The premium paid for the capped call transactions was $37 million, which was recorded against Capital in excess of par in the Statement of Consolidated Equity.
3. Inventories
Inventories at December 31 were as follows:
4. Property, Plant and Equipment
Property, plant and equipment at December 31 were as follows:
Capitalized Exploratory Well 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:
Additions to capitalized exploratory well costs primarily related to drilling activity at the Stabroek license offshore Guyana and in the Gulf of Mexico in 2016 and 2015. In 2014, additions related to the Deepwater Tano/Cape Three Points license offshore Ghana and in Kurdistan. Reclassifications to wells, facilities and equipment based on the determination of proved reserves primarily related to Equatorial Guinea in 2015, and the Stampede development project in the Gulf of Mexico in 2014.
Capitalized exploratory well costs charged to expense include the following:
2016: At the Hess-operated Equus natural gas project, offshore the North West Shelf of Australia in the fourth quarter of 2016, we terminated a joint front-end engineering study with a third party natural gas liquefaction joint venture and notified the Australian government of our intent to defer the project. As a result, we expensed all well costs associated with the project, including an exploration well completed in the second quarter of 2016, totaling $830 million. In the second quarter,
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we expensed costs associated with two exploration wells at the non-operated Sicily project in the Gulf of Mexico where hydrocarbons were encountered but we decided not to pursue the project due to the current price environment and the limited time remaining on the leases. We also expensed the cost of an unsuccessful exploration well at the non-operated Melmar project in the Gulf of Mexico, where noncommercial quantities of hydrocarbons were encountered.
2015: At the Dinarta Block in the Kurdistan Region of Iraq, we expensed an exploration well resulting from our and our partners’ decision to cease further drilling and relinquish the block. At the Deepwater/Tano Cape Three Points block, offshore Ghana, we expensed well costs primarily related to natural gas discoveries where we were unable to sufficiently progress appraisal negotiations with the regulator, and we expensed three wells with discovered resources offshore Australia that we determined would not be included in the development concept for the Equus project.
2014: At Green Canyon Block 469 in the Gulf of Mexico, we expensed a previously capitalized exploration well where it was determined no further development activities were planned.
The preceding table excludes exploratory dry hole costs of $167 million (2015: $54 million; 2014: $66 million), which were incurred and subsequently expensed in the same year.
Exploratory well costs capitalized for greater than one year following completion of drilling were $511 million at December 31, 2016, separated by year of completion as follows (in millions):
Ghana: Approximately 55% of the capitalized well costs in excess of one year relates to our Deepwater Tano/Cape Three Points license (Hess 50% license interest), offshore Ghana. In 2014 we drilled three successful appraisal wells. Well results continue to be evaluated and development planning is progressing. The government of Côte d’Ivoire has challenged the maritime border between it and the country of Ghana, which includes a portion of our Deepwater Tano/Cape Three Points license. We are unable to proceed with development of this license until there is a resolution of this matter, which may also impact our ability to develop the license. The International Tribunal for Law of the Sea is expected to render a final ruling on the maritime border dispute in 2017. Under terms of our license and subject to resolution of the border dispute, we declared commerciality for four discoveries, including the Pecan Field which would be the primary development hub for the block in March 2016. We are continuing to work with the government on how best to progress work on the block given the maritime border dispute.
Guyana: Approximately 20% of the capitalized well costs in excess of one year relates to the Stabroek Block, offshore Guyana (Hess 30% participating interest), where the operator, Esso Exploration and Production Guyana Limited, announced a significant oil discovery at the Liza-1 well in the second quarter of 2015. During 2016, the operator completed a 17,000 square kilometer 3D seismic acquisition on the Stabroek Block and drilled the Liza-2 and Liza-3 wells, both of which encountered hydrocarbons. Pre-development planning is underway and we expect to be in a position to sanction the first phase of the Liza development in 2017.
Gulf of Mexico: Approximately 20% of the capitalized well costs in excess of one year relates to an appraisal well in the northern portion of the Shenzi Field (Hess 28% participating interest) in the Gulf of Mexico, where hydrocarbons were encountered in the fourth quarter of 2015. The operator is evaluating plans for developing this area of the field.
JDA: Approximately 5% of the capitalized well costs in excess of one year relates to the JDA in the Gulf of Thailand where hydrocarbons were encountered in three successful exploration wells drilled in the western part of Block A-18. The operator is currently evaluating well results and formulating future drilling plans in the area.
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5. Goodwill
The changes in the carrying amount of goodwill were as follows:
In the second quarter of 2015, we established a new operating segment, the Bakken Midstream segment which had previously been reported as part of the Onshore reporting unit within the E&P operating segment. The E&P operating segment previously had two reporting units, Offshore which had allocated goodwill of $1,098 million and Onshore which had allocated goodwill of $760 million prior to forming the Bakken Midstream operating segment. Upon formation of the Bakken Midstream operating segment, we allocated $375 million of goodwill from the Onshore reporting unit to the Bakken Midstream operating segment based on the relative fair values of the Bakken Midstream business and the remainder of the Onshore reporting unit. There was no change to the composition of the Offshore reporting unit. See Note 6, Impairment for further information.
6. Impairment
In 2016, we recorded a pre-tax impairment charge of $67 million ($21 million after income taxes and noncontrolling interest) to impair older specification rail cars in our Midstream segment based on estimated salvage values, which approximate fair value and represent a Level 3 fair value measurement as defined under accounting standards.
In 2015, we recorded pre-tax goodwill impairment charges totaling $1,483 million ($1,483 million after income taxes). As a result of establishing the Bakken Midstream operating segment in the second quarter of 2015, (see Note 5, Goodwill), we performed impairment tests on the Offshore and Onshore reporting units prior to creation of the Bakken Midstream segment in accordance with accounting standards for goodwill. No impairment resulted from this assessment. In addition, we performed separate impairment tests at June 30, 2015, on the allocated goodwill to the Bakken Midstream segment and Onshore reporting unit of the E&P segment following the creation of the Bakken Midstream segment. No impairment existed for the Bakken Midstream segment, but goodwill allocated to the Onshore reporting unit of $385 million did not pass the impairment test, and as a result was reduced to its implied fair value of zero based on a hypothetical purchase price allocation as stipulated in the accounting standards. In addition, as part of the further deterioration in crude oil prices in the fourth quarter of 2015, we determined goodwill allocated to the Offshore reporting unit of $1,098 million did not pass the impairment test, and as a result was reduced to its implied fair value of zero based on a hypothetical purchase price allocation as stipulated in the accounting standards. Fair value of our Onshore and Offshore reporting units were determined using multiple valuation techniques, including projected discounted cash flows of producing assets and known development projects. The determination of projected discounted cash flows depended on estimates of oil and gas reserves, future prices, operating costs, capital expenditures, discount rate and timing of future net cash flows. We also considered the relative market valuation of similar peer companies using market multiples, and other observable market data, in assessing fair value of each reporting unit. The valuation methodologies used represent Level 3 measurements.
As a result of the prevailing low crude oil price in 2015, we also recognized an impairment charge of $133 million pre-tax ($83 million after income taxes) relating to our legacy conventional North Dakota assets based on projected discounted cash flows, using similar Level 3 inputs to those discussed above.
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7. Bakken Midstream Joint Venture
On July 1, 2015, we sold a 50% interest in HIP to Global Infrastructure Partners (GIP) for net cash consideration of approximately $2.6 billion. HIP and its affiliates primarily comprise our Bakken Midstream operating segment which provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, transportation of crude oil by rail car, terminaling and loading crude oil and natural gas liquids, and the storage and terminaling of propane, primarily in the Bakken shale play of North Dakota. The Bakken Midstream operating segment currently generates substantially all of its revenues under long-term, fee-based agreements with our E&P operating segment and intends to pursue additional throughput volumes from third parties in the Williston Basin area. We operate the Bakken Midstream assets and operations, including routine and emergency maintenance and repair services under various operational and administrative services agreements.
The tariff agreements between our E&P operating segment and the Bakken Midstream entities became effective on January 1, 2014 and are 10-year, fee-based commercial agreements, with HIP having the sole option to renew the agreements for an additional 10-year term. These agreements include minimum volume commitments based on dedicated production, inflation escalators and fee recalculation mechanisms. The Bakken Midstream segment has minimal direct commodity price exposure, and the E&P segment retains ownership of the crude oil, natural gas or natural gas liquids processed, terminaled, stored or transported by the Bakken Midstream segment.
We consolidate the activities of HIP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles. We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power, through our 50% ownership, to direct those activities that most significantly impact the economic performance of HIP. This conclusion was based on a qualitative analysis that considered HIP’s governance structure, the commercial agreements between HIP and us, and the voting rights established between the members which provide us the ability to control the operations of HIP.
As a result of the sale to GIP in 2015, we recorded an after-tax gain of $763 million in additional paid-in-capital and $1,298 million in noncontrolling interest representing GIP’s proportional share of our basis in the net assets of HIP. The results attributable to GIP’s 50% ownership are reported within Net income (loss) attributable to noncontrolling interests in the Statement of Consolidated Income, while the carrying amount of GIP’s equity is included as Noncontrolling interests in the Consolidated Balance Sheet.
Upon formation, the joint venture incurred $600 million of borrowings through a 5-year Term Loan A facility with the proceeds distributed equally to the partners. At December 31, 2016, HIP liabilities totaling $841 million (2015: $831 million) are on a nonrecourse basis to Hess Corporation, while HIP assets available to settle the obligations of HIP included Cash and cash equivalents totaling $2 million (2015: $3 million) and Property, plant and equipment totaling $2,528 million (2015: $2,358 million).
8. Dispositions
2016: We sold miscellaneous non-core assets during the year for proceeds totaling approximately $100 million and recognized net pre-tax gains totaling $23 million ($14 million after income taxes).
2015: We sold approximately 13,000 acres of Utica dry gas acreage for a sale price of approximately $120 million. This transaction resulted in a pre-tax gain of $49 million ($31 million after income taxes). We also disposed of our interest in Algeria and recognized a pre-tax loss of $21 million ($21 million after income taxes) and sold land associated with our former joint venture interest in the Bayonne Energy Center for $20 million, resulting in a pre-tax gain of $20 million ($13 million after income taxes).
2014: We completed the sale of our interest in the Pangkah asset, offshore Indonesia for cash proceeds of approximately $650 million, which resulted in a pre-tax gain of $31 million ($10 million loss after income taxes). We also completed the sale of our interests in Thailand for cash proceeds of approximately $805 million, which resulted in a pre-tax gain of $706 million ($706 million after income taxes). In addition, we completed the sale of approximately 77,000 net acres in the dry gas area of the Utica shale play including related wells and facilities through multiple transactions, for cash proceeds of $1,075 million and recorded a pre-tax gain of $62 million ($35 million after income taxes). In June, we completed the sale of our joint venture interest in an electric generating facility in Newark, New Jersey for cash proceeds of $320 million, resulting in a pre-tax gain of approximately $13 million ($8 million after income taxes). In September, we sold our joint venture interest in Bayonne Energy Center for $79 million, which did not result in a gain or loss. Also in September, we completed the sale of our interest in an exploration asset in the United Kingdom North Sea for $53 million, which resulted in a pre-tax
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
gain of $33 million ($33 million after income taxes).
9. Discontinued Operations
The results of operations for our divested Marketing and Refining businesses, which included ownership of the energy trading partnership through February 2015 and retail marketing through September 2014, have been reported as discontinued operations in the Statement of Consolidated Income and the Statement of Consolidated Cash Flows for all periods presented.
Sales and other operating revenues and income from discontinued operations were as follows:
2015: In February, we sold our interest in HETCO, which was subsequently renamed Hartree Partners, LP (Hartree). Pursuant to the terms of the sale, Hartree was permitted to utilize our guarantees issued in favor of Hartree's existing counterparties until November 12, 2015, provided that new trades were for a period of one year or less, complied with certain credit requirements, and net exposures remained within value at risk limits previously applied by us. The guarantees remain in effect until the qualifying trades outstanding at November 12, 2015 mature. We have the right to seek reimbursement from Hartree and a separate Hartree credit support facility upon any counterparty draw on the applicable guarantee from us. No draws on the guaranteed trades have occurred through December 31, 2016.
2014: In September, we completed the sale of our retail business for cash proceeds of approximately $2.8 billion. This transaction resulted in a pre-tax gain of $954 million ($602 million after income taxes) after deducting the net book value of assets, including $115 million of goodwill. During the year, we recorded pre-tax gains of $275 million ($171 million after income taxes) relating to the liquidation of last-in, first-out (LIFO) inventories associated with the divested downstream operations. In addition, we recorded pre-tax charges totaling $308 million ($202 million after income taxes) for impairments, environmental matters, severance and exit related activities associated with the divestiture of downstream operations. We also recognized a pre-tax charge of $115 million ($72 million after income taxes) related to the termination of lease contracts and the purchase of 180 retail gasoline stations in preparation for the sale of the retail operations. In January, our retail business acquired our partners’ 56% interest in WilcoHess, a retail gasoline joint venture, for approximately $290 million and the settlement of liabilities. In connection with this business combination, we recorded a pre-tax gain of $39 million ($24 million after income taxes) to remeasure the carrying value of our original 44% equity interest in WilcoHess to fair value, including recognition of goodwill in the amount of $115 million. The assets and liabilities acquired from WilcoHess were included in the sale of the retail business in September 2014.
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10. HOVENSA LLC
HOVENSA LLC (HOVENSA), a 50/50 joint venture between the Corporation’s subsidiary, Hess Oil Virgin Islands Corp. (HOVIC), and Petroleos de Venezuela S.A. (PDVSA), had previously shut down its U.S. Virgin Islands refinery in 2012 and filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States District Court of the Virgin Islands in September 2015. To fund HOVENSA's sale process and orderly wind-down, HOVENSA entered into a $40 million debtor-in-possession credit facility with HOVENSA’s owners, the terms of which were approved by the Bankruptcy Court. On December 1, 2015, the Bankruptcy Court entered an order approving the sale of HOVENSA’s terminal and refinery assets to Limetree Bay Terminals, LLC (Limetree). The Senate of the U.S. Virgin Islands approved the sale on December 29, 2015, and the sale to Limetree was completed on January 4, 2016. On January 19, 2016, the Bankruptcy Court entered an order confirming HOVENSA’s Chapter 11 plan of liquidation (the “Liquidation Plan”). Under the Liquidation Plan, HOVENSA established a liquidating trust to distribute certain assets and sale proceeds to its creditors, established an environmental response trust to administer to HOVENSA’s remaining environmental obligations and to conduct an orderly wind-down of its remaining activities. The Liquidation Plan also provided for releases of any claims held by HOVENSA and its bankruptcy estate against us and HOVIC, which were effective on the effective date of the Liquidation Plan. In connection with the Liquidation Plan and HOVENSA’s asset sale, we relinquished our claims against HOVENSA to recover the 2012 and 2015 promissory notes issued by HOVENSA. In addition, we assumed the HOVENSA pension plan upon the effective date of the Liquidation Plan. In 2015, we recorded a charge of $30 million primarily representing the estimated net difference between the HOVENSA pension plan obligation and fair value of the plan assets.
11. Asset Retirement Obligations
The following table describes changes to our asset retirement obligations:
The liabilities settled or disposed of related primarily to abandonment activities conducted at the Valhall field offshore Norway in 2016 and 2015, the Gulf of Mexico in 2016, and the U.K. North Sea in 2015. The revisions in 2016 primarily relate to the South Arne Field, offshore Denmark, as a result of a 20-year extension to the license that extends expiry to 2047. Other revisions in 2016 and 2015 reflect changes in the expected scope of operations and updates to service and equipment costs. The fair value of sinking fund deposits that are legally restricted for purposes of settling asset retirement obligations, which are included in non-current Other assets in the Consolidated Balance Sheet, was $102 million at December 31, 2016 and $79 million at December 31, 2015.
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12. Debt
Long-term debt at December 31 consisted of the following:
(a)
At December 31, 2016 the fair value of total debt amounted to $7,548 million (2015: $6,515 million).
(b)
The aggregate total debt maturing during the next five years is as follows (in millions): 2017: $112; 2018: $123; 2019: $448; 2020: $598 and 2021: $-.
Debt refinancing transaction: In September 2016, Hess Corporation issued $1 billion of 4.30% senior notes, due in April 2027, and $500 million of 5.80% senior notes, due in April 2047 primarily to fund the repurchase of tendered higher-coupon debt and redemption of near-term maturities. We used proceeds of $1.38 billion to purchase or redeem $650 million principal amount of 8.125% notes due 2019, $196 million principal amount of 7.875% notes due 2029, $66 million principal amount of 7.30% notes due 2031 and $300 million principal amount of 1.30% notes due 2017. As a result of this debt refinancing transaction, we incurred a charge of $148 million for the loss on extinguishment of the tendered and redeemed notes.
Debt excluding Bakken Midstream: At December 31, 2016, Hess Corporation’s fixed-rate public notes had a gross principal amount of $5,938 million (2015: $5,650 million) and a weighted average interest rate of 6.0% (2015: 6.4%). Our long-term debt agreements, including the revolving credit facility, contain financial covenants that restrict the amount of total borrowings and secured debt. The most restrictive of these covenants allow us to borrow up to an additional $4,585 million of secured debt at December 31, 2016. In 2016, we capitalized $61 million of interest (2015: $45 million; 2014: $76 million).
Hess Corporation has a $4 billion syndicated revolving credit facility that expires in January 2020. Borrowings on the facility will generally bear interest at 1.3% above the London Interbank Offered Rate (LIBOR). The interest rate will be higher if our credit rating is lowered. The facility contains a financial covenant that limits the amount of total borrowings on the last day of each fiscal quarter to 65% of the Corporation’s total capitalization, defined as total debt plus stockholders’ equity. At December 31, 2016, Hess Corporation had no outstanding borrowings or letters of credit issued against the syndicated revolving credit facility and was in compliance with this financial covenant.
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Letters of credit: Outstanding letters of credit at December 31 were as follows:
(a)
At December 31, 2016, committed and uncommitted lines have expiration dates through 2018.
(b)
At December 31, 2016, $27 million relates to contingent liabilities and $161 million relates to liabilities recorded in the Consolidated Balance Sheet (2015: $32 million and $81 million, respectively).
Debt related to Bakken Midstream: In July 2015, HIP, a 50/50 joint venture between us and GIP, incurred $600 million of debt through a 5-year Term Loan A facility. The proceeds from the debt were distributed equally to the partners. HIP also entered into a $400 million 5-year syndicated revolving credit facility, which can be used for borrowings and letters of credit, and is expected to fund the joint venture’s operating activities and capital expenditures. Borrowings on both loan facilities are non-recourse to Hess Corporation and generally bear interest at LIBOR plus an applicable margin ranging from 1.10% to 2.00%. The interest rate is subject to adjustment based on the joint venture’s leverage ratio, which is calculated as total debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). If the joint venture obtains credit ratings, pricing levels will be based on its credit ratings in effect from time to time. The joint venture is subject to customary covenants in the credit agreement, including financial covenants that generally require a leverage ratio of no more than 5.0 to 1.0 for the prior four fiscal quarters and an interest coverage ratio, which is calculated as EBITDA to interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters. HIP is in compliance with all debt covenants at December 31, 2016, and its financial covenants do not currently impact their ability to issue indebtedness to fund future capital expenditures.
13. Share-based Compensation
We have established and maintain a Long-term Incentive Plan (LTIP), as amended, for the granting of restricted common shares, performance share units (PSUs) and stock options to our employees. As of December 31, 2016, the total number of authorized common stock under LTIP, as amended, was 38.0 million shares, of which we have 10.6 million shares available for issuance. Outstanding restricted stock and PSUs generally vest three years from the date of grant. Restricted common shares are valued based on the prevailing market price of our common stock on 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 peer companies over a three-year performance period ending December 31 of the year prior to settlement of the grant. 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.
Share-based compensation expense consisted of the following:
(a)Includes benefit related to discontinued operations of $4 million for 2014.
Based on share-based compensation awards outstanding at December 31, 2016, unearned compensation expense, before income taxes, will be recognized in future years as follows (in millions): 2017-$66, 2018-$35, and 2019-$6.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Share-based compensation activity consisted of the following:
As of December 31, 2016, there were 6.6 million outstanding stock options (5.5 million exercisable) with a weighted average remaining contractual life of 3.6 years (2.6 years for exercisable options) and an aggregated intrinsic value of $27 million ($14 million for exercisable options). The weighted average exercise price for options exercisable at December 31, 2016 was $69.71 per share.
The following weighted average assumptions were utilized to estimate the fair value of stock options:
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. Retirement Plans
We have funded noncontributory defined benefit pension plans for a significant portion of our employees. In addition, we have an unfunded supplemental pension plan covering certain employees, which provides incremental payments that would have been payable from our 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, we maintain 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 benefit obligations, the fair value of plan assets, and the funded status of our pension and postretirement medical plans:
(a)
The change in discount rate in 2016 resulted in total actuarial losses of approximately $175 million.
(b)
Benefit payments include lump-sum settlement payments of $65 million in 2016 (2015: $41 million).
Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following:
(a)
The after-tax deficit reflected in Accumulated other comprehensive income (loss) was $660 million at December 31, 2016 (2015: $563 million deficit).
At December 31, 2016, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $2,471 million and $203 million, respectively (2015: $2,223 million and $196 million, respectively).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The net periodic benefit cost for funded and unfunded pension plans, and the postretirement medical plan, is as follows:
For 2017, the pension and postretirement medical expense is estimated to be approximately $61 million, which includes approximately $67 million related to the amortization of unrecognized net actuarial losses.
The weighted average actuarial assumptions used for funded and unfunded pension plans were as follows:
The actuarial assumptions used for postretirement medical plan, 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.
Our 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 our 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables provide the fair value of the financial assets of the funded pension plans as of December 31, 2016 and 2015 in accordance with the fair value measurement hierarchy described in Note 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies.
(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 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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:
We expect to contribute approximately $52 million to our funded pension plans in 2017.
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):
We also have several defined contribution plans for certain eligible employees. Employees may contribute a portion of their compensation to these plans and we match a portion of the employee contributions. We recorded expense of $25 million in 2016 for contributions to these plans (2015: $28 million; 2014: $32 million).
15. Exit and Disposal Costs
In 2016, we incurred severance expense of $55 million (2015: $13 million; 2014: $76 million) and paid accrued severance costs of $52 million (2015: $57 million; 2014: $170 million). The severance charge in 2016 primarily resulted from a realignment of our organizational structure communicated in November 2016. Severance charges in 2015 and 2014 resulted from a divestiture program announced in 2013. Severance charges were based on amounts incurred under ongoing severance arrangements or other statutory requirements, plus amounts earned under enhanced benefit arrangements. The expense associated with the enhanced benefits was recognized ratably over the estimated service period required for the employee to earn the benefit upon termination. In 2015, we recorded other exit related costs of $15 million (2014: $65 million). In 2016, we paid $2 million (2015: $21 million; 2014: $158 million) for accrued facility and other exit costs. The facility and other exit costs related to charges associated with the cessation of use of certain leased office space, contract terminations, and costs associated with the shutdown of Port Reading refining operations.
At December 31, 2016, we had accrued liabilities for severance costs of $36 million (2015: $33 million) and accrued liabilities for exit costs of $17 million (2015: $19 million). Of the accrued liabilities at December 31, 2016, all severance costs are expected to be paid in 2017 and the exit costs of $14 million will be paid over the next several years.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
16. Income Taxes
The provision (benefit) for income taxes from continuing operations consisted of:
(a)
Includes charges of $3,749 million in 2016 to establish valuation allowances on net deferred tax assets which is discussed further below.
Income (loss) from continuing operations before income taxes consisted of the following:
(a)
Includes substantially all of our interest expense, corporate expense and the results of commodity hedging activities.
The components of deferred tax liabilities and deferred tax assets at December 31 were as follows:
At December 31, 2016, we have recognized a gross deferred tax asset related to net operating loss carryforwards of $5,767 million before application of valuation allowances. The deferred tax asset is comprised of $2,610 million attributable to foreign net operating losses which begin to expire in 2024, $2,766 million attributable to U.S. federal operating losses which begin to expire in 2021 and $391 million attributable to losses in various U.S. states which began to expire in 2017. The deferred tax asset attributable to foreign net operating losses, net of valuation allowances, is $1,468 million, substantially all of which relates to loss carryforwards in Norway. The deferred tax asset attributable to U.S. federal net operating losses, net of valuation allowances, is $39 million. A full valuation allowance is established against the deferred tax asset attributable to U.S. state net operating losses. At December 31, 2016, we have U.S. federal, U.S. state and foreign alternative minimum tax credit carryforwards of $77 million which can be carried forward indefinitely, and approximately $6 million of other business credit carryforwards. The deferred tax asset attributable to these credits, net of valuation allowances, is $1 million. A full valuation allowance is established against our foreign tax credit carryforwards of $81 million, which begin to expire in 2017.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2016, the Balance Sheet reflects a $5,450 million valuation allowance against the net deferred tax assets for multiple jurisdictions based on application of the relevant accounting standards, with $3,749 million recorded in the fourth quarter of 2016 related primarily to the U.S., Denmark (hydrocarbon tax only), and Malaysia. The charge in 2016 is comprised of net deferred tax assets as of the beginning of the year totaling $2,683 million and additional net deferred tax assets recognized during the year of $1,066 million. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The cumulative loss incurred over the three-year period ending December 31, 2016 constitutes significant objective negative evidence. Such objective negative evidence limits our ability to consider subjective positive evidence, such as our projections of future taxable income, resulting in the recognition of a valuation allowance against the net deferred tax assets for these jurisdictions. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income change or if objective negative evidence in the form of cumulative losses is no longer present and additional weight can be given to subjective evidence.
In the Consolidated Balance Sheet, deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at December 31 as follows:
The difference between our effective income tax rate from continuing operations and the U.S. statutory rate is reconciled below:
(a)
The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the mix of income among high and low tax rate jurisdictions.
Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits:
The December 31, 2016 balance of unrecognized tax benefits includes $233 million that, if recognized, would impact our effective income tax rate. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately $85 million due to settlements with taxing authorities or other resolutions, as well as lapses in statutes of limitation. At December 31, 2016, our accrued interest and penalties related to unrecognized tax benefits is $29 million (2015: $74 million).
We have not recognized deferred income taxes on the portion of undistributed earnings of foreign subsidiaries expected to be indefinitely reinvested in foreign operations. At December 31, 2016, we have undistributed earnings from foreign subsidiaries, which we expect to be indefinitely reinvested in foreign operations, of approximately $7.6 billion. We have not measured the unrecognized deferred tax liability related to these earnings because this determination is not practicable.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We file income tax returns in the U.S. and various foreign jurisdictions. We are no longer subject to examinations by income tax authorities in most jurisdictions for years prior to 2005.
17. Outstanding and Weighted Average Common Shares
The following table provides the changes in our outstanding common shares:
(a)
See Note 18, Share Repurchase Plan.
The following table presents the calculation of basic and diluted earnings per share:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes the number of antidilutive shares excluded from the computation of diluted shares:
In 2016, 2015 and 2014, cash dividends declared on common stock totaled $1.00 per share ($0.25 per quarter).
18. Share Repurchase Plan
In 2013, our Board of Directors authorized the repurchase of up to $4.0 billion in aggregate purchase price of our common stock. In May 2014, the Board of Directors approved an increase in the program to $6.5 billion. Repurchases under this program to date have been as follows:
As of December 31, 2016, we are authorized, but not required, to purchase additional common stock up to a value of $1.15 billion.
19. Supplementary Cash Flow Information
The following information supplements the Statement of Consolidated Cash Flows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20. Leased Assets
We and certain of our subsidiaries lease drilling rigs, office space and other assets for varying periods under contractual obligations accounted for as operating leases. Operating lease expenses for drilling rigs used to drill development wells and successful exploration wells are capitalized. At December 31, 2016, 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):
Rental expense was as follows:
21. Guarantees, Contingencies and Commitments
Guarantees and Contingencies
At December 31, 2016, we have $27 million in letters of credit for which we are contingently liable. In addition, we are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in our consolidated financial statements when it is probable that 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, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing claims, lawsuits and 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 lengthy discovery, conciliation and/or arbitration proceedings, or litigation before a loss or range of loss can be reasonably estimated. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such lawsuits, claims and proceedings, including the matters described below, is not expected to have a material adverse effect on our financial condition. However, we could incur judgments, enter into settlements or revise our opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.
We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have 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 us. The principal allegation in all cases was that gasoline containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. The majority of the cases asserted against us have been settled. In June 2014, the Commonwealth of Pennsylvania and the State of Vermont each filed independent lawsuits alleging that we and all major oil companies with operations in each respective state, have damaged the groundwater in those states by introducing thereto gasoline with MTBE. The Pennsylvania suit has been removed to Federal court and has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. The suit filed in Vermont is proceeding there in a state court. In September 2016, the State of Rhode Island also filed a lawsuit in Federal court alleging that we and other major oil companies damaged the groundwater in Rhode Island by introducing thereto gasoline with MTBE.
In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the Lower Passaic River. The NJDEP is also seeking natural resource damages. The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Jersey we previously owned. We and over 70 companies entered into an Administrative Order on Consent with the Environmental Protection Agency (EPA) to study the same contamination; this work remains ongoing. We and other parties settled a cost recovery claim by the State of New Jersey and also agreed with EPA to fund remediation of a portion of the site. In April 2014, the EPA issued a Focused Feasibility Study (FFS) proposing to conduct bank-to-bank dredging of the lower eight miles of the Lower Passaic River at an estimated cost of $1.7 billion. On March 4, 2016, the EPA issued a Record of Decision (ROD) in respect of the lower eight miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion. The ROD does not address the upper nine miles of the Lower Passaic River, which may require additional remedial action. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given that the EPA has not selected a remedy for the entirety of the Lower Passaic River, total remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us because there are numerous other parties who we expect will share in the cost of remediation and damages and our former terminal did not store or use contaminants which are of the greatest concern in the river sediments and could not have contributed contamination along most of the river’s length.
In March 2014, we received an Administrative Order from EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. The remedy includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. EPA has estimated that this remedy will cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. Our alleged liability derives from our former ownership and operation of a fuel oil terminal adjacent to the Canal. We indicated to EPA that we would comply with the Administrative Order and are currently contributing funding for the Remedial Design based on an interim allocation of costs among the parties. At the same time, we are participating in an allocation process whereby neutral experts selected by the parties will determine the final shares of the Remedial Design costs to be paid by each of the participants. The parties have not yet addressed the allocation of costs associated with implementing the remedy that is currently being designed.
On January 18, 2017, we entered into a Consent Decree with the North Dakota Department of Health resolving alleged non-compliance with North Dakota’s air pollution laws and provisions of the federal Clean Air Act. Pursuant to the Consent Decree, we are required to implement corrective actions, including implementation of a leak detection and repair program, at most of our existing facilities in North Dakota. We were assessed a base penalty of $922,000, which is subject to adjustment based on the date we complete corrective actions required under the terms of the Consent Decree. We made an initial penalty payment of $55,000 during the first quarter of 2017.
From time to time, we are involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. We 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 our financial condition, results of operations or cash flows.
Unconditional Purchase Obligations and Commitments
The following table shows aggregate information for certain unconditional purchase obligations and commitments at December 31, 2016 which are not included elsewhere within these Consolidated Financial Statements:
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
22. Segment Information
We currently have two operating segments, Exploration and Production and Bakken Midstream. The Exploration and Production operating segment explores for, develops, produces, purchases and sells crude oil, natural gas liquids and natural gas with production operations primarily in the United States (U.S.), Denmark, Equatorial Guinea, the JDA, Malaysia, and Norway. The Bakken Midstream operating segment provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, transportation of crude oil by rail car, terminaling and loading crude oil and natural gas liquids, and the storage and terminaling of propane, primarily in the Bakken shale play of North Dakota. All unallocated costs are reflected under Corporate, Interest and Other.
The following table presents operating segment financial data for continuing operations (in millions):
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents financial information by major geographic area:
(a)
Of the total Europe, Property, plant and equipment (net), Norway represented $3,893 million in 2016 (2015: $4,108 million).
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
23. Related Party Transactions
The following table presents our related party transactions:
(a)
We acquired our partners’ 56% interest in WilcoHess in January 2014 for approximately $290 million. See Note 9, Discontinued Operations.
24. Financial Risk Management Activities
In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural gas as well as changes in interest rates and foreign currency values. In the disclosures that follow, corporate financial risk management activities refer to the mitigation of these risks through hedging activities. We maintain a control environment for all of our financial risk management under the direction of our Chief Risk Officer. Our Treasury department is responsible for administering foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors.
Corporate Financial Risk Management Activities: Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas we produced or by reducing our 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 our crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which we conduct the business with the intent of reducing exposure to foreign currency fluctuations. These forward contracts comprise various currencies, primarily the British Pound and Danish Krone. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.
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.
The gross notional amounts of financial risk management derivative contracts outstanding at December 31, were as follows:
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table below reflects the gross and net fair values of the risk management derivative instruments, all of which are based on Level 2 inputs:
Derivative contracts designated as hedging instruments:
Commodity: In 2015, crude oil price hedging contracts increased E&P Sales and other operating revenues by $126 million, including losses of $48 million associated with changes in the time value of crude oil collars. In 2014, crude oil price hedging contracts increased E&P Sales and other operating revenues by $193 million. There were no crude oil hedge contracts in 2016.
Interest rate swaps: At December 31, 2016, we had interest rate swaps with gross notional amounts of $350 million (2015: $1,300 million), which were designated as fair value hedges. During 2016, we settled existing interest rate swaps and received cash proceeds of $5 million (2015: $41 million). 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. In 2016, we recorded an increase of $6 million, excluding accrued interest, in the fair value of interest rate swaps and a corresponding adjustment in the carrying value of the hedged fixed-rate debt (2015: $4 million increase; 2014: $1 million increase).
Derivative contracts not designated as hedging instruments:
Foreign exchange: Total foreign exchange gains and losses were a gain of $26 million in 2016 (2015: loss of $21 million; 2014: loss of $43 million) and are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income. A component of foreign exchange gains or losses is the result of foreign exchange derivative contracts that are not designated as hedges which amounted to a gain of $62 million in 2016 (2015: gain of $98 million; 2014: gain of $117 million).
The after-tax foreign currency translation adjustments included in the Statement of Consolidated Comprehensive Income amounted to a gain of $56 million for the year-ended December 31, 2016 (2015: loss of $344 million; 2014: loss of $756 million). Cumulative currency translation adjustments reduced stockholders’ equity by $1,045 million at December 31, 2016 and $1,101 million at December 31, 2015.
Credit Risk: We are 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, 2016, our Accounts receivable-Trade were concentrated with the following counterparty industry segments: Integrated companies - 37%, Independent E&P companies - 19%, National oil companies - 16%, Storage and transportation companies - 10%, Refining and marketing companies - 7% and Others - 11%. We reduce risk related to certain counterparties, where applicable, by using master netting arrangements and requiring collateral, generally cash or letters of credit.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
At December 31, 2016, we had outstanding letters of credit totaling $188 million (2015: $113 million).
Fair Value Measurement: We have other short-term financial instruments, primarily cash equivalents, accounts receivable and accounts payable, for which the carrying value approximated fair value at December 31, 2016 and December 31, 2015. In addition, the disclosure for fair value of long-term debt in Note 12, Debt was based on Level 2 inputs.
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 ended December 31, 2016, we produced crude oil, natural gas liquids and natural gas principally in the United States (U.S.), Europe (Norway and Denmark), Africa (Equatorial Guinea, Libya and Algeria) and Asia and Other (the Malaysia/Thailand Joint Development Area (JDA), Malaysia, Thailand, and Indonesia). Exploration activities were also conducted, or are planned, in certain of these areas as well as additional countries. See Note 8, Dispositions in the Notes to Consolidated Financial Statements.
Costs Incurred in Oil and Gas Producing Activities
(a)
Includes $13 million of exploration costs incurred for unconventional assets in 2016 (2015: $45 million; 2014: $283 million).
(b)
Includes a reduction of $188 million for asset retirement obligations related to net accruals and revisions in 2016 (2015: $151 million increase; 2014: $326 million increase).
(c)
Costs incurred in oil and gas producing activities in Norway, were as follows for the years ended December 31:
*
Includes net 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 (losses) on sales of oil and gas properties, sales of purchased crude oil, natural gas liquids and natural gas, interest expense and other non-operating income. Therefore, these results are on a different basis than the net income (loss) from E&P operations reported in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 22, Segment Information in the Notes to Consolidated Financial Statements.
(a)
Includes charges to establish valuation allowances against net deferred tax assets amounting to $2,920 million. The charge is attributed to the geographic region in which the operations occurred that gave rise to the net deferred tax asset (United States - $1,144 million, Europe - $486 million, Africa - $249 million and Asia & Other - $1,041 million).
(b)
Results of operations for oil and gas producing activities in Norway were as follows for the years ended December 31.
Proved Oil and Gas Reserves
Our 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. Our estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed by our internal teams of geoscience and reservoir engineering professionals. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles 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. Our proved reserves are subject to certain risks and uncertainties, which are discussed in Item 1A. Risk Factors of this Form 10-K.
Internal Controls
The Corporation maintains internal controls over its oil and gas reserve estimation processes which are administered by the Corporation’s Director, Global Reserves and its Chief Financial Officer. Estimates of reserves are prepared by technical staff who 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 87 through 92). 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 2016 was Mr. David DuBois, Director Global Reserves. Mr. DuBois 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 Petroleum Engineering. His experience has been primarily focused on oil and gas subsurface understanding and reserves estimation in both domestic and international areas. Mr. DuBois is 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
We engaged the consulting firm of DeGolyer and MacNaughton (D&M) to perform an audit of the internally prepared reserve estimates on certain fields aggregating 78% of 2016 year-end reported reserve quantities on a barrel of oil equivalent basis (2015: 83%). 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 1, 2017, 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, 2016 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 less than 3% 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.
Crude Oil Prices Used to Estimate Proved Reserves
Proved reserves are calculated using the average price during the twelve-month period before December 31 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions. Crude oil prices used in the determination of proved reserves at December 31, 2016 were $42.68 per barrel for WTI (2015: $50.13; 2014: $94.42) and $44.45 per barrel for Brent (2015: $55.10; 2014: $101.35). New York Mercantile Exchange (NYMEX) natural gas prices used were $2.54 per mcf in 2016 (2015: $2.63; 2014: $4.30). Revisions primarily associated with lower crude oil prices reduced proved reserves by 29 million boe at December 31, 2016 and 234 million boe at December 31, 2015.
At December 31, 2016, spot prices for WTI oil closed at $53.75 per barrel. If crude oil prices in 2017 average below those used in determining 2016 proved reserves, we may recognize further negative revisions of our December 31, 2016 proved undeveloped reserves. In addition, we may recognize negative revisions to proved developed reserves, which can vary significantly by asset due to differing operating cost structures. Conversely, price increases in 2017 above those used in determining 2016 proved reserves could result in positive revisions to proved reserves at December 31, 2017. It is difficult to estimate the magnitude of any potential negative or positive change in proved reserves as of December 31, 2017, due to a number of factors that are currently unknown, including 2017 crude oil prices, any revisions based on 2017 reservoir performance, and the levels to which industry costs will change in response to movements in commodity prices.
Following are the Corporation’s proved reserves:
(a)
The impact of changes in selling prices on the reserve estimates for production sharing contracts with cost recovery provisions in 2016 was an increase to Crude oil and condensate reserves of 1 million barrels (2015: 5 million barrels increase; 2014: 1 million barrels increase).
(b)
Crude oil and condensate and Natural gas liquids proved reserves in Norway were as follows:
(a)
The impact of changes in selling prices on the reserve estimates for production sharing contracts with cost recovery provisions in 2016 was an increase to natural gas reserves of 12 million mcf (2015: 42 million mcf increase; 2014: 7 million mcf increase).
(b)
Natural gas production in 2016 includes 15 million mcf used for fuel (2015: 14 million mcf; 2014: 10 million mcf).
(c)
Excludes approximately 165 million mcf of carbon dioxide gas for sale or use in company operations.
(d)
Natural gas and Total proved reserves in Norway were as follows:
Extensions, discoveries and other additions (‘Additions’)
2016: Total Additions were 69 million boe, of which 45 million boe (34 million barrels of crude oil, 2 million barrels of natural gas liquids and 55 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves were primarily from drilling activity in the Bakken shale play in North Dakota and from a 20-year extension to the license for the South Arne Field, offshore Denmark, which extends expiry to 2047. Additions to proved undeveloped reserves were 24 million boe (11 million barrels of crude oil, 3 million barrels of natural gas liquids and 59 million mcf of natural gas) and are discussed in further detail below.
2015: Total Additions were 82 million boe, of which 33 million boe (19 million barrels of crude oil, 5 million barrels of natural gas liquids and 54 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves were primarily from drilling activity in the Bakken shale play in North Dakota and the Utica shale play in Ohio. Additions to proved undeveloped reserves were 49 million boe (33 million barrels of crude oil, 7 million barrels of natural gas liquids and 56 million mcf of natural gas) and are discussed in further detail below.
2014: Total Additions were 245 million boe, of which 32 million boe (17 million barrels of crude oil, 5 million barrels of natural gas liquids and 62 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves were primarily from drilling activity in the Bakken shale play in North Dakota and the Utica shale play in Ohio. Additions to proved undeveloped reserves were 213 million boe (135 million barrels of crude oil, 21 million barrels of natural gas liquids and 340 million mcf of natural gas) and are discussed in further detail below.
Revisions of previous estimates
2016: Total revisions of previous estimates amounted to a net increase of 74 million boe, of which net positive revisions increased proved reserves by 103 million boe (54 million barrels of crude oil, 5 million barrels of natural gas liquids and 265 million mcf of natural gas) and negative revisions associated with lower crude oil prices reduced proved reserves by 29 million boe (23 million barrels of crude oil, 1 million barrels of natural gas liquids and 30 million mcf of natural gas). Total revisions of proved developed reserves amounted to a net increase of 41 million boe (5 million barrels decrease of crude oil, 7 million barrels increase of natural gas liquids and 235 million mcf increase of natural gas) reflecting improved expected recoveries in the Bakken shale play in North Dakota, completion of incremental development activities at the North Malay Basin, partially offset by negative revisions at the Valhall field offshore Norway due to changes in estimated recoveries of natural gas liquids and natural gas, and negative price revisions mostly related to crude oil reserves. Revisions associated with proved undeveloped reserves are discussed in further detail below.
2015: Total revisions of previous estimates were a net decrease of 280 million boe. Negative revisions associated with lower crude oil prices reduced proved reserves at December 31, 2015 by 234 million boe (158 million barrels of crude oil; 26 million barrels of natural gas liquids and 299 million mcf of natural gas), including 220 million boe (147 million barrels of crude oil, 22 million barrels of natural gas liquids and 303 million mcf of natural gas) associated with proved undeveloped reserves. Other net negative revisions were 46 million boe, which also primarily related to proved undeveloped reserves that are discussed below.
2014: Total negative revisions to proved reserves were 52 million boe (56 million barrels of crude oil and 4 million barrels of natural gas liquids, partially offset by an increase of 50 million mcf in natural gas), that primarily reflect changes in proved undeveloped reserves which are discussed in further detail below.
Proved Undeveloped Reserves
Following are the Corporation’s proved undeveloped reserves:
(a)
In 2014, the Corporation divested of its remaining operations in Indonesia and Thailand.
Extensions, discoveries and other additions (‘Additions’)
2016: In the United States, additions were at the Utica shale play in Ohio as result of changes in well design that improved both well economics and recoverability, and at the Bakken shale play in North Dakota due to drilling plans. In Europe, additions were primarily from a 20-year extension to the license for the South Arne Field, offshore Denmark, which extends expiry to 2047.
2015: In the United States, we recognized additions of 29 million boe in the Bakken shale play and 13 million boe related to the Tubular Bells and Penn State fields in the Gulf of Mexico based on drilling plans for new wells.
2014: In the United States, we recognized additions of 97 million boe in the Bakken shale play and 18 million boe in the Utica shale play based on drilling plans for new wells. We also recognized 21 million boe related to the sanction of the Stampede development project in the Gulf of Mexico. At the Valhall Field offshore Norway, additions resulting from planned drilling activity were 37 million boe. At the North Malay Basin offshore Malaysia, we recognized additions of 31 million boe upon signing a gas sales agreement for the full field development phase of the project.
Revisions of previous estimates
2016: Total positive reserve revisions were 33 million boe. Technical revisions increased reserves by 44 million boe and were primarily from an improved well design at the Bakken shale play in North Dakota, which was partially offset by negative revisions at the Valhall Field offshore Norway due to changes in expected recoveries of natural gas liquids and natural gas. Negative revisions resulting from lower commodity prices totaled 11 million boe and were primarily in the Bakken shale play.
2015: Total negative reserve revisions were 292 million boe. Negative revisions resulting from lower commodity prices totaled 220 million boe, and were primarily in the Bakken shale play (127 million boe), the North Malay Basin offshore Malaysia (34 million boe), the Valhall Field offshore Norway (30 million boe) and the Stampede project in the Gulf of Mexico (21 million boe). Other negative revisions included 48 million boe related to planned drilling dates of certain Bakken wells moving beyond 2020 due to reprioritization of the drilling schedule, and 26 million boe at the Valhall Field offshore Norway primarily related to drilling schedule changes.
2014: In the United States, Bakken negative revisions of 47 million boe were as a result of well performance and reprioritization of well locations in the drilling schedule resulting in certain wells moving beyond 2019. At the Valhall Field offshore Norway, downward technical revisions amounted to 9 million boe.
Transfers to proved developed reserves (‘Transfers’)
2016: Transfers from proved undeveloped reserves to proved developed reserves included 21 million boe in the Bakken shale play and 13 million at the Tubular Bells and Conger fields in the Gulf of Mexico associated with drilling activity.
2015: Transfers from proved undeveloped reserves to proved developed reserves included 43 million boe in the Bakken shale play and 11 million boe at the Valhall Field offshore Norway associated with drilling activity. Transfers of 61 million boe related to the JDA gas field in the Gulf of Thailand primarily resulted from additional development and drilling activity.
2014: Transfers from proved undeveloped reserves into proved developed reserves included 38 million boe in the Bakken shale play and 15 million boe at the Valhall Field offshore Norway associated with drilling activity. Transfers of 30 million boe were the result of achieving first production from the Tubular Bells Field in the Gulf of Mexico.
In 2016, capital expenditures of $589 million were incurred to convert proved undeveloped reserves to proved developed reserves (2015: $1,931 million; 2014: $3,110 million). Capital expenditures in 2014 include production facilities and subsea infrastructure for the Tubular Bells field in the Gulf of Mexico which achieved first production in late 2014.
We are also 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 80 million boe or 7% of total proved reserves at December 31, 2016. Most of the proved undeveloped reserves in excess of five years relate to the Valhall Field offshore Norway.
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, 2016 are presented separately below, as well as volumes produced and received during 2016, 2015 and 2014 from these production sharing contracts.
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, as well as including the effect of tax deductions and tax credits and allowances relating to the Corporation’s proved oil and gas reserves. Future net cash flows are discounted at the prescribed rate of 10%.
The prices used for the discounted future net cash flows in 2016 were $42.68 per barrel for WTI (2015: $50.13; 2014: $94.42) and $44.45 per barrel for Brent (2015: $55.10; 2014: $101.35). New York Mercantile Exchange (NYMEX) natural gas prices used were $2.54 per mcf in 2016 (2015: $2.63; 2014: $4.30) and do not include the effects of commodity hedges. Selling prices have in the past, and can in the future, fluctuate significantly. As a result, selling prices used in the disclosure of future net cash flows may not be representative of future selling prices. In addition, the discounted future net cash flow estimates do not include exploration expenses, interest expense or corporate general and administrative expenses. The
amount of tax deductions, credits, and allowances relating to the Corporation’s proved oil and gas reserves can change year to year due to factors including changes in proved reserves, variances in actual pre-tax cash flows from forecasted pre-tax cash flows in historical periods, and the impact to year-end carryforward tax attributes associated with deducting in the Corporation’s income tax returns exploration expenses, interest expense, and corporate general and administrative expenses that are not contemplated in the standardized measure computations. The future net cash flow estimates could be materially different if other assumptions were used.
(a)
At December 31, the standardized measure of discounted future net cash flows relating to proved reserves in Norway were as follows:
(b)
The Petroleum Tax Act provides for compensation by the Norwegian government to a company upon cessation of its exploration and production activities on the Norwegian Continental Shelf in an amount equal to the tax values of unutilized tax losses and certain other tax attributes, including dismantlement expenditures incurred after production has ceased that would qualify for compensation at an effective tax rate of 78%. Due to the low crude oil price used in the 2016 computation, future income taxes reflect cash inflows for Norway of $2.1 billion on an undiscounted basis. The corresponding present value reflected in the Standardized Measure of Discounted Future Net Cash Flows at December 31, 2016 is $70 million.
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, Depreciation, depletion and amortization and Impairments.
(b)
Includes an after-tax charge of $52 million related to dry hole and related expenses, an after-tax charge of $22 million associated with the termination of a drilling rig contract and an after-tax gain of $17 million related to the sale of undeveloped acreage, onshore United States.
(c)
Includes a noncash charge of $3,749 million to establish valuation allowances against net deferred tax assets at December 31, 2016, an after-tax charge of $693 million to fully impair the carrying value of our Equus natural gas project offshore the North West Shelf of Australia, and other after-tax charges of $145 million related to offshore rig costs, loss on debt extinguishment, impairment of rail cars, severance and other charges.
(d)
Includes after-tax charges of $77 million related to dry hole and related expenses and an after-tax charge of $16 million for inventory write-offs.
(e)
Includes a non-taxable charge of $385 million related to goodwill impairment associated with our onshore E&P business and an after-tax charge of $21 million related to terminated international office space.
(f)
Includes an after-tax gain of $31 million from the sale of Utica dry gas acreage, $50 million tax benefit associated with an international investment incentive, and an after-tax charge of $43 million of dry hole, lease impairment and other exploration expenses.
(g)
Includes a non-taxable charge of $1,098 million related to goodwill impairment, exploration charges of $178 million primarily related to previously capitalized well costs, and a net after-tax impairment charge of $83 million associated with our legacy conventional assets in North Dakota. We also recorded an after-tax charge of $41 million for our estimated liability resulting from HOVENSA LLC’s bankruptcy settlement.
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, 2016, 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, 2016.
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, 2016 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. Financial Statements and Supplementary Data 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 Corporation’s definitive proxy statement for the 2017 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 Corporation’s definitive proxy statement for the 2017 annual meeting of stockholders.
Executive Officers of the Corporation
The following table presents information as of February 23, 2017 regarding executive officers of the Corporation:
*
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 their name on May 4, 2016.
Except for Ms. Lowery-Yilmaz and Mr. Slentz, each of the above officers has been employed by the Corporation or its affiliates in various managerial and executive capacities for more than five years. Prior to joining the Corporation, Ms.
Lowery-Yilmaz served in senior executive positions in exploration and production at BP plc and Mr. Slentz served in senior executive positions in human resources at Peabody Energy and its affiliates.
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 Corporation’s definitive proxy statement for the 2017 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 Corporation’s definitive proxy statement for the 2017 annual meeting of stockholders.
See Equity Compensation Plans in Item 5. Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities 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 Corporation’s definitive proxy statement for the 2017 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 Corporation’s definitive proxy statement for the 2017 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
The exhibits required to be filed pursuant to Item 15(b) of Form 10-K are listed in the Exhibit Index filed herewith, which Exhibit Index is incorporated herein by reference.
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 23rd day of February 2017.
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 23, 2017
/s/ James H. Quigley
James H. Quigley
Director and
Chairman of the Board
February 23, 2017
/s/ Rodney F. Chase
Rodney F. Chase
Director
February 23, 2017
/s/ Terrence J. Checki
Terrence J. Checki
Director
February 23, 2017
/s/ Leonard S. Coleman Jr.
Leonard S. Coleman Jr.
Director
February 23, 2017
/s/ Edith E. Holiday
Edith E. Holiday
Director
February 23, 2017
/s/ dr. Risa Lavizzo-Mourey
Dr. Risa Lavizzo-Mourey
Director
February 23, 2017
/s/ Marc S. Lipschultz
Marc S. Lipschultz
Director
February 23, 2017
/s/ David Mcmanus
David McManus
Director
February 23, 2017
/s/ dr. Kevin O. Meyers
Dr. Kevin O. Meyers
Director
February 23, 2017
/s/ John H. Mullin, III
John H. Mullin, III
Director
February 23, 2017
/s/ Fredric G. Reynolds
Fredric G. Reynolds
Director
February 23, 2017
/s/ John P. Rielly
John P. Rielly
Senior Vice President and Chief
Financial Officer
(Principal Financial and Accounting Officer)
February 23, 2017
/s/ William G. Schrader
William G. Schrader
Director
February 23, 2017
Schedule II
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2016, 2015 and 2014
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 Registrant, dated May 22, 2013, incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on May 22, 2013.
3(3)
Certificate of Amendment to the Restated Certificate of Incorporation of Registrant, effective May 12, 2014, incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on May 13, 2014.
3(4)
Certificate of Designations of the 8.00% Series A Mandatory Convertible Preferred Stock of Hess Corporation, including Form of Certificate for the 8.00% Series A Mandatory Convertible Preferred Stock incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on February 10, 2016.
3(5)
By-laws of Registrant incorporated by reference to Exhibit 3(2) of Form 8-K of Registrant filed on November 9, 2015.
4(1)
Five-Year Credit Agreement, dated as of January 21, 2015, 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 January 27, 2015.
4(2)
Amendment No. 1 to the Five-Year Credit Agreement, dated as of July 10, 2015 among Hess Corporation, the subsidiaries party thereto, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent, incorporated by reference to Exhibit 10(2) of Form 10-Q of Registrant for the three months ended June 30, 2015.
4(3)
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(4)
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) of Form 10-Q of Registrant for the three months ended September 30, 1999.
4(5)
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, as amended, on August 9, 2001.
4(6)
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)(4) under the Securities Act of 1933, as amended, on March 1, 2002.
4(7)
Indenture dated as of March 1, 2006, between Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase Bank, N.A., as Trustee, including form of Note, incorporated by reference to Exhibit 4 to Registrant’s Form S-3ASR filed on March 1, 2006.
4(8)
Form of 8.125% Note due 2019, incorporated by reference to Exhibit 4(2) to Form 8-K of the Registrant, filed on February 4, 2009.
4(9)
Form of 6.00% Note due 2040, incorporated by reference to Exhibit 4(1) to Form 8-K of Registrant filed on December 15, 2009.
4(10)
Form of 5.60% Note due 2041, incorporated by reference to Exhibit 4(1) to Form 8-K of Registrant filed on August 12, 2010.
4(11)
Form of 1.30% Note due 2017, incorporated by reference to Exhibit 4(2) to Form 8-K of Registrant filed on June 25, 2014.
4(12)
Form of 3.50% Note due 2024, incorporated by reference to Exhibit 4(3) to Form 8-K of Registrant filed on June 25, 2014.
4(13)
Deposit Agreement, dated as of February 10, 2016, among Hess Corporation and Computershare Inc. and Computershare Trust Company, N.A., as depositary, on behalf of all holders from time to time of the receipts issued thereunder, including Form of Depositary Receipt for the Depositary Shares incorporated by reference to Exhibit 4(2) of Form 8-K of Registrant filed on February 10, 2016.
4(14)
Form of 4.30% Note due 2027, incorporated by reference to Exhibit 4(1) to Form 8-K of Registrant filed on September 28, 2016.
4(15)
Form of 5.80% Note due 2047, incorporated by reference to Exhibit 4(2) to Form 8-K of Registrant filed on September 28, 2016.
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 Securities and Exchange Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.
10(1)*
Annual Cash Incentive Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on March 4, 2016.
10(2)*
Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for the 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 the fiscal year ended December 31, 2006.
10(4)*
2016 Performance Incentive Plan for Senior Officers, as approved by stockholders on May 4, 2016, incorporated by reference to Exhibit 10(1) to Form 8-K of Registrant filed on May 10, 2016.
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 the 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 the fiscal year ended December 31, 2004.
10(9)*
Amended and Restated 2008 Long-term Incentive Plan, incorporated by reference to Form 8-K of the Registrant filed on May 12, 2015.
10(10)*
Forms of Awards under Registrant’s 2008 Long-term Incentive Plan, incorporated by reference to Exhibit 10(14) of Form 10-K of Registrant for the fiscal year ended December 31, 2009.
10(11)*
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(12)*
Form of Restricted Stock Award Agreement under Registrant’s Amended and Restated 2008 Long-term Incentive Plan, incorporated by reference to Exhibit 10(2) of Form 10-Q of Registrant for the three months ended March 31, 2015.
10(13)*
Form of Performance Award Agreement for the three-year period ending December 31, 2016 under Registrant’s 2008 Long-term Incentive Plan, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended March 31, 2014.
10(14)*
Form of Performance Award Agreement for the three-year period ending December 31, 2017 under Registrant’s Amended and Restated 2008 Long-term Incentive Plan, incorporated by reference to Exhibit 10(3) of Form 10-Q of Registrant for the three months ended March 31, 2015.
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)*
Form of Amended and Restated Change of Control Termination Benefits Agreement, dated as of May 29, 2009, 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)*
Amended and Restated 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 Form 10-K of Registrant 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 Michael Turner and John B.Hess).
10(18)
Form of Change in Control Termination Benefits Agreement, dated as of August 3, 2015, between the Registrant and Michael R. Turner, incorporated by reference to Exhibit 10(3) of Form 10-Q of Registrant for the three months ended June 30, 2015. Substantially identical agreements (differing only in the signatories thereto) were entered into between the Registrant and four other senior officers.
10(19)*
Agreement between Registrant and Gregory P. Hill, relating to Mr. Hill’s 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 Mr. Goodell’s 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, dated as of May 16, 2013, among Registrant, Elliott Associates, L.P. and Elliott International, L.P., incorporated by reference to Exhibit 99(1) of Form 8-K of Registrant filed on May 22, 2013.
Subsidiaries of Registrant.
23(1)
Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 23, 2017.
23(2)
Consent of DeGolyer and MacNaughton dated February 23, 2017.
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 1, 2017, on proved reserves audit as of December 31, 2016 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.