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(1)	Final investment decision has been made.

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(2)	Represents multiple ongoing development projects.

(3)	See Update on Israel – Israel Natural Gas Framework, below.

•	positive revisions of 91 MMBoe;

•	extensions and other additions of 100 MMBoe related to our onshore US horizontal drilling programs; and

•	additions of 269 MMBoe related to our acquisition of Eagle Ford Shale and Permian Basin assets;

•	record production volumes of 130 MMBoe;

•	downward revisions of 307 MMBoe that were commodity price driven; and

•	reduction of 6 MMBoe as a result of asset sales.

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(1)	Excludes exploratory wells drilled and suspended awaiting a sanctioned development plan or being assessed for economic viability. See Drilling Activity, below.

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•	the timely approval of asset development permits and plans and export permits;

•	benchmarking future domestic contract pricing for an interim period until market competition is established, whereby such contracts are indexed to existing domestic and export contracts;

•	resolution of antitrust and competition concerns, whereby we would divest Karish and Tanin within 14 months and reduce our ownership in Tamar to 25% within six years;

•	the de-linking of Tamar export timing from Leviathan, enabling Tamar expansion to move forward; and

•	support for investment and industry growth through stabilization assurance.

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•	the Audit Committee of our Board of Directors reviews significant reserves changes on an annual basis;

•	fields that meet a minimum reserve quantity threshold, newly sanctioned development projects, and certain fields selected on a rotational basis, which combined represent over 80% of our proved reserves, are audited by Netherland, Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, on an annual basis; and

•	NSAI is engaged by, and has direct access to, the Audit Committee. See Third-Party Reserves Audit, below.

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•	the transfer to unproved reserves of 183 MMBoe due to negative price revisions attributed to low commodity price outlook and negative revisions of 48 MMBoe due to reduced future development activity, primarily in the DJ Basin;

•	54 MMBoe positive revisions primarily in the Marcellus Shale, Eagle Ford Shale and Permian Basin due to current drilling and development plans.

•	147 MMBoe in the DJ Basin;

•	50 MMBoe in the Marcellus Shale;

•	102 MMBoe in the Eagle Ford Shale;

•	31 MMBoe in the Permian Basin; and

•	14 MMBoe in the deepwater Gulf of Mexico primarily associated with the Gunflint project.

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70 MMBoe in the Alba field, offshore Equatorial Guinea, all of which have been recorded as PUDs for over five years and are attributable to a sanctioned compression project which is currently under construction and expected to come online mid-2016. These volumes, which will be recovered through existing wells, will be reclassified to proved developed at start-up, currently expected in second quarter 2016; and

•	71 MMBoe in Israel primarily in the Tamar and Tamar Southwest fields, including PUDs of 32 MMBoe related to the Tamar Southwest field, which is awaiting government approval of the development plan.

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•	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Proved Reserves for a discussion of changes in proved reserves;

•	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Reserves for further discussion of our reserves estimation process; and

•

Item 8. Financial Statements and Supplementary Data – Supplementary Oil and Gas Information (Unaudited) for additional information regarding estimates of crude oil, natural gas and NGL reserves, including estimates of proved, proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in the standardized measure of discounted future net cash flows.

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(1)	Average production cost includes crude oil and natural gas operating costs and workover and repair expense and excludes production and ad valorem taxes and transportation expenses.

(2)	Natural gas from the Alba field is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.

(3)	Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.

(1)	Includes approximately 124,000 gross undeveloped acres and 58,000 net undeveloped acres attributable to our Karish and Tanin fields which were subsequently divested in January 2016.

(2)	Our working interest for Cyprus undeveloped acreage decreased from 70% as of December 31, 2015, to 35% upon closing of the sale of a 35% interest in the Cyprus undeveloped acreage to BG Group during 2016.

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(1)	Approximately 25% of 2016 gross acreage is located in core areas where we currently expect to continue development activities and/or extend the lease terms.

(2)	We currently intend to extend certain leases prior to expiration in accordance with license terms. Approximately 99,000 gross acres (47,000 net) will expire and not be extended.

(3)	Will expire in accordance with the terms of the Exploitation License for the Aphrodite field.

(4)	The acreage represents the Tilapia PSC. We extended the lease during 2015. However, the extension timeline varies and it is therefore unknown what percentage of acreage will be relinquished in 2016.

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(1)	Includes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well.

(2)	Includes wells pending completion activities.

(3)	Includes the Karish and Tanin exploratory wells which have been classified as assets held for sale as of December 31, 2015 and were divested in January 2016.

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•	the Ministry of Mines, Industry and Energy which, under such laws as the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, regulates our exploration, development and production activities offshore Equatorial Guinea;

•	the Ministry of National Infrastructures, Energy and Water Resources which regulates our exploration and development activities offshore Israel and the Israeli electricity market into which we sell our natural gas production;

•	the Israeli Antitrust Commission which reviews Israel's domestic natural gas sales and ownership in offshore blocks and leases;

•	the Ministry of Energy, Commerce, Industry and Tourism which regulates our exploration and development activities offshore Cyprus;

•	the Department of Energy and Climate Change which regulates our activities in the UK sector of the North Sea; and

•	the Department of Mineral Resources which regulates our exploration activities offshore the Falkland Islands.

•

the Bureau of Land Management (BLM), the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), which under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act, have certain authority over our operations on federal lands and waters, particularly in the Rocky Mountains and deepwater Gulf of Mexico;

•	the Office of Natural Resources Revenue, which under the Federal Oil and Gas Royalty Management Act of 1982, has certain authority over our payment of royalties, rentals, bonuses, fines, penalties, assessments, and other revenue;

•

the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration (OSHA), which under laws such as the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act, the Safe Drinking Water Act, and the Occupational Safety and Health Act have certain authority over environmental, health and safety matters affecting our operations;

•	the US Fish and Wildlife Service (FWS) and US National Marine Fisheries Service, which under the Endangered Species Act have authority over activities that may result in the take of any endangered or threatened species or its habitat;

•	the US Army Corps of Engineers, which under the Clean Water Act has authority to regulate the construction of structures involving the fill of certain waters and wetlands subject to federal jurisdiction, including well pads, pipelines and roads;

•	the Federal Energy Regulatory Commission (FERC), which under laws such as the Energy Policy Act of 2005 has certain authority over the marketing and transportation of crude oil, natural gas and NGLs we produce onshore and from the deepwater Gulf of Mexico; and

•	the Department of Transportation (DOT), which has certain authority over the transportation of products, equipment and personnel necessary to our onshore US and deepwater Gulf of Mexico operations.

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•	documentation of environmental changes that are coincident with shale gas production;

•	development of technology or management practices that mitigate any unintended environmental changes; and

•	development of monitoring technologies to (1) assess the impact of shale gas production on air quality and (2) determine if zonal isolation between producing formations and drinking water aquifers is maintained after hydraulic fracturing.

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•	Items 1. and 2. Business and Properties – Regulations;

•	Item 1A. Risk Factors; and

•	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Risk and Insurance Program.

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•	further significant reductions of our revenues, profit margins, operating income and cash flows;

•	reduction in the amount of crude oil, natural gas and NGLs that we can produce economically, leading to shut-in or early abandonment of producing wells and increased capital requirements for abandonment operations;

•	certain properties in our portfolio becoming economically unviable;

•	additional impairments of proved or unproved properties;

•	loss of undeveloped acreage if our production is shut-in or we are unable to make scheduled delay rental payments;

•	use of cash flow to satisfy minimum take or pay obligations under throughput agreements if production is suspended;

•	further reduction, or suspension, of our 2016 capital investment program, or significant reductions in future capital investment programs, resulting in a reduced ability to develop our reserves;

•	delay, postponement or cancellation of some of our exploration or development projects;

•	inability to meet exploration commitments, leading to loss of leases or exploration rights;

•	divestments of properties to generate funds to meet cash flow or liquidity requirements;

•	limitations on our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;

•	inability to meet scheduled interest and/or debt payments or payments due under operating or capital leases;

•	a series of credit rating downgrades or other negative rating actions could increase our cost of financing, and may increase our requirements to post collateral as financial assurance of performance under certain other contracts which, in turn, could have a negative impact on our liquidity;

•	changes in corporate structure that could lead to loss of key personnel and interrupt our business activities;

•	limitations on our access to sources of capital, such as debt and equity; and

•	reduction or suspension of dividends on our common stock.

•	further declines in our stock price;

•	additional asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment; and

•	additional counterparty credit risk exposure on commodity hedges and joint venture receivables.

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•	economic factors impacting gross domestic product growth rates of countries around the world;

•	global demand for crude oil, natural gas and NGLs;

•	Organization of Petroleum-Exporting Countries (OPEC) spare capacity relative to global crude oil supply and crude oil pricing strategies;

•	global factors impacting supply quantities of crude oil, natural gas and NGLs, including US crude oil and NGL supply, and the possible addition of Iranian crude oil supplies to world markets and/or new natural gas supplies;

•	technology advances that increase crude oil, natural gas and NGL production;

•	developments in the domestic and global crude oil markets due to the lifting of the US crude oil export ban;

•	developments in the global LNG market, including exports from the US;

•	actions taken by foreign hydrocarbon-producing nations;

•	geopolitical conditions and events, including generational leadership or regime changes, outcomes of presidential elections, changes in government energy policies, or instability/armed conflict in hydrocarbon-producing regions;

•	the existence of government imposed price controls and/or product subsidies;

•	fluctuations in US dollar exchange rates, the currency in which the world's crude oil trade is denominated;

•	the price and availability of alternative fuels, including coal, solar, wind, nuclear energy and biofuels;

•	the long-term impact on the crude oil market of the use of natural gas as an alternative fuel for road transportation;

•	the availability of pipeline capacity and infrastructure;

•	the level and effect of trading in commodity futures markets, including by commodity price speculators and others;

•	the effectiveness of worldwide conservation measures;

•	the availability of crude oil transportation and refining capacity;

•	weather conditions;

•	demand for electricity as well as natural gas used as fuel for electricity generation;

•	fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and its impacts on crude oil demand as a transportation fuel;

•	access to government-owned and other lands for exploration and production activities; and

•	domestic and foreign governmental regulations and taxes.

•	a continued low commodity price environment;

•	inability to develop a feasible project design;

•	lack of government approvals for projects;

•	delays obtaining project approvals from joint venture partners;

•	delays in obtaining project financing on terms that are acceptable to us and/or our partners;

•	changes in Israel's regulatory framework for the development of natural gas resources, which could impact timing of development of the Leviathan project and partner funding;

•	potential negative impact of natural gas dispute between Israel and Egypt on Leviathan natural gas marketing activities;

•	inability to successfully negotiate natural gas sales and purchase agreements in quantities and at prices to support a final investment decision;

•	inability to attract and/or retain a sufficient quantity of personnel with the requisite skills to bring these complex projects to production;

•	potential organizational changes and high turnover attributed to current pricing / operating environment may hinder our ability to deliver projects on time;

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•	significant delays in delivery of essential items or performance of services, cost overruns, supplier insolvency, or other critical supply failure;

•	civil disturbances, anti-development activities, legal challenges or other potential interruptions which could prevent access or project approval; and

•	drilling hazards, accidents or natural disasters.

•

renegotiation, modification or nullification of existing contracts, such as may occur pursuant to future regulations enacted as a result of changes in Israel's antitrust, export and natural gas development policies, or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can result in an increase in the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;

•	loss of revenue, property and equipment as a result of actions taken by host nations, such as expropriation or nationalization of assets or termination of contracts;

•	disruptions caused by territorial or boundary disputes in certain international regions;

•	changes in drilling or safety regulations in other countries;

•	laws and policies of the US and foreign jurisdictions affecting foreign investment, taxation, trade and business conduct;

•	potential for Israel gas production and regional exports to be interrupted by political conditions and events, and regional instability or armed conflict in the region;

•	potential decline in bipartisan US support of Israeli government policies which could impact trade with Israel;

•	difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;

•	foreign exchange or repatriation restrictions;

•	war, piracy, acts of terrorism or civil unrest;

•	international monetary fluctuations and changes in the relative value of the US dollar as compared with the currencies of other countries in which we conduct business; and

•	other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.

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•	restrict resource access or investment in lease holdings;

•	reduce exploration activities, which could have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;

•	have a negative impact on the ability of us and/or our partners to obtain financing;

•	cause delay in or cancellation of development plans, which could also have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;

•	reduce the profitability of our projects, resulting in decreases in net income and cash flows with the potential to make future investments uneconomical;

•	result in currently producing projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;

•	require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income and cash flow;

•	restrict our ability to compete with imported volumes of crude oil or natural gas; and/or

•	adversely affect the price of our common stock.

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•	increased volatility in global crude oil, natural gas and NGL prices which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;

•	negative impact on the world crude oil supply if infrastructure or transportation are disrupted, leading to further commodity price volatility;

•	difficulty in attracting and retaining qualified personnel to work in areas with potential for conflict;

•	inability of our personnel or supplies to enter or exit the countries where we are conducting operations;

•	disruption of our operations due to evacuation of personnel;

•	inability to deliver our production due to disruption or closing of transportation routes;

•	reduced ability to export our production due to efforts of countries to conserve domestic resources;

•	damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;

•	damage to or destruction of property belonging to our natural gas purchasers leading to interruption of natural gas deliveries, claims of force majeure, and/or termination of natural gas sales contracts, resulting in a reduction in our revenues;

•	inability of our service and equipment providers to deliver items necessary for us to conduct our operations;

•	lack of availability of drilling rig, oilfield equipment or services if third party providers decide to exit the region;

•	shutdown of a financial system, communications network, or power grid causing a disruption to our business activities; and

•	capital market reassessment of risk and reduction of available capital making it more difficult for us and our partners to obtain financing for potential development projects.

•	pipeline ruptures and spills;

•	fires, explosions, blowouts and well cratering;

•	equipment malfunctions and/or mechanical failure on high-volume, high-impact wells;

•	malfunctions and/or mechanical failure at terminals or other onshore delivery points;

•	leaks or spills occurring during the transfer of hydrocarbons from an FPSO to an oil tanker;

•	loss of product occurring as a result of transfer to a rail car or train derailments;

•	formations with abnormal pressures and basin subsidence which could result in leakage or loss of access to hydrocarbons;

•	release of pollutants;

•	spills, leaks or discharges of fluids used in or produced in the course of operations, especially those that reach surface water or groundwater; and

•	security breaches, cyber attacks, piracy or terroristic acts.

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•	hurricanes, tropical storms, cyclones, windstorms, or “superstorms” which could affect our operations in areas such as Texas, deepwater Gulf of Mexico, Marcellus Shale or Eastern Mediterranean;

•	winter storms and snow which could affect our operations in the DJ Basin and Marcellus Shale;

•	extremely high temperatures, which could affect third party gathering and processing facilities in the DJ Basin and Texas;

•	severe droughts resulting in new restrictions on water usage in the DJ Basin, Marcellus Shale and Texas;

•	volcanoes which could affect our operations offshore Equatorial Guinea;

•	flooding, or increases in sea level, which could affect our operations in low-lying areas;

•	harsh weather and rough seas offshore the Falkland Islands, which could limit certain exploration activities; and

•	other natural disasters.

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•	lower commodity price outlook;

•	title problems;

•	near-term lease expiration;

•	decisions impacting allocation of capital;

•	compliance with environmental and other governmental requirements;

•	availability of market, or costs to develop infrastructure;

•	increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and qualified personnel;

•	unexpected drilling conditions;

•	pressure or other irregularities in formations;

•	equipment failures or accidents; and

•	adverse weather conditions.

•	delay or reduce the profitability of our Tamar and/or Leviathan development projects;

•	delay or preclude closing of project financing arrangements for us or our partners; and/or

•	render future exploration and development projects uneconomic.

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•	declines in commodity prices, which reduce revenues and available cash flows;

•	changes in fiscal regimes impacting royalties, taxes, fees, resource access, or level of government participation in projects;

•	delay in government project approval, or other regulatory actions, which could have a negative impact on the ability to obtain financing;

•	downgrades in credit rating or liquidity problems;

•	increased banking regulation which could reduce access to sources of funding or make funding more expensive; and

•	regional conflict, which could result in capital market reassessment of risk and withdrawal of capital.

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•	blocked development;

•	denial or delay of permits;

•	shortening of lease terms or reduction in lease size;

•	restrictions on installation or operation of gathering, processing or pipeline facilities;

•	restrictions on the transportation of oil and gas;

•	restrictions on the use of certain operating practices, such as hydraulic fracturing;

•	reduced access to water supplies or restrictions on water disposal;

•	limited access or damage to or destruction of our property;

•	legal challenges or lawsuits;

•	targeted activist shareholder campaigns;

•	increased regulation of our business;

•	damaging publicity about the Company;

•	increased costs of doing business;

•	reduction in demand for our products; and

•	other adverse effects on our ability to develop our properties and expand production.

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•	unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

•	data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

•	data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;

•	a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt

•	of our major development projects, effectively delaying the start of cash flows from the project;

•	a cyber attack on a third party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenues;

•	a cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;

•	a cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues;

•	a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

•	a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

•	business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.

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•	new municipal or state land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;

•	local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;

•	landowner, community and/or governmental opposition to infrastructure development;

•	regulation of federal land by the BLM;

•	anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, disruption of drilling, or damage to equipment;

•	the presence of threatened or endangered species or of their habitat;

•	disputes regarding leases; and

•	disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements.

•	exploration activities in frontier areas may not result in commercially productive quantities of crude oil, natural gas and NGL reserves;

•	the remote location of the Falkland Islands makes it more difficult and time-consuming to transport personnel, equipment and supplies;

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•	the operating environment offshore the Falkland Islands includes harsh weather and rough seas which could limit seismic surveys and other exploration activities during certain periods; and

•	pandemics and epidemics, which may adversely affect our business operations through travel or other restrictions; and

•	there have been numerous acts of piracy, kidnapping, civil strife, regional conflict, border disputes, cross-border violence, and war, as well as violence associated with corruption, drug trafficking and regime changes in certain areas.

•	a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

•	we may be at a competitive disadvantage as compared to similar companies that have less debt;

•	a covenant contained in our Credit Agreement provides that our total debt to capitalization ratio (as defined) will not exceed 65% at any time, which may make additional borrowings more expensive, thereby affecting our flexibility in planning for, and reacting to, changes in the economy and in our industry;

•	additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;

•	changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and/or availability of future financing, and lower ratings will increase the interest rate and fees we pay on our unsecured revolving credit facility (Credit Facility); and

•	we may be more vulnerable to general adverse economic and industry conditions.

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•	large multi-national, integrated oil companies;

•	state-controlled national oil companies;

•	US independent oil and gas companies;

•	service companies engaging in exploration and production activities; and

•	private oil and gas equity funds.

•	seeking to acquire desirable producing properties or new leases for future exploration;

•	marketing our crude oil, natural gas and NGL production;

•	seeking to acquire the equipment and expertise necessary to operate and develop properties; and

•	attracting and retaining employees with certain skills.

•	historical production from the area compared with production from other areas;

•	the assumed effects of regulations by governmental agencies, including the SEC;

•	assumptions concerning future crude oil, natural gas, and NGL prices;

•	anticipated development cycle time;

•	future development costs;

•	future operating costs;

•	impacts of cost recovery provisions in contracts with foreign governments;

•	severance and excise taxes; and

•	workover and remedial costs.

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•	increase the costs of drilling exploratory and development wells;

•	cause delays in, or preclude, the development of our projects resulting in longer development cycle times;

•	result in additional operating and capital costs;

•	divert our cash flows from capital investments in order to maintain liquidity;

•	increase or remove liability caps for claims of damages from oil spills;

•	increase our share of civil or criminal fines or sanctions for actual or alleged violations if a well incident were to occur; and

•	limit our ability to obtain additional insurance coverage, at a level that balances the cost of insurance and our desired rates of return, to protect against any increase in liability.

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•	our growth strategies;

•	our ability to successfully and economically explore for and develop crude oil, natural gas and NGL resources;

•	anticipated trends in our business;

•	our future results of operations;

•	our liquidity and ability to finance our exploration, development, and acquisition activities;

•	market conditions in the oil and gas industry;

•	our ability to make and integrate acquisitions;

•	the impact of governmental fiscal terms and/or regulation, such as that involving the protection of the environment or marketing of production, as well as other regulations; and

•	access to resources.

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(1)	Amounts adjusted for the 2-for-1 stock split which occurred during second quarter 2013.

(2)	2015 includes $61 million cash received in the Rosetta Merger, an all-stock transaction.

(3)	Goodwill was fully impaired at December 31, 2015. See Item 8. Financial Statements and Supplementary Data – Note 4. Goodwill.

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•	Executive Overview;

•	Operating Outlook;

•	Results of Operations;

•	Proved Reserves;

•	Liquidity and Capital Resources; and

•	Critical Accounting Policies and Estimates.

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•	we have a high-quality, globally diversified portfolio of assets, the majority of which are held by production and provide investment flexibility;

•	we have achieved sustainable cost reductions (and are well-positioned on the US supply curve) impacting both operating expenses and capital items, positively impacting operating cash flows;

•	we are focused on operational efficiencies and projects that can be profitable in the current commodity price environment;

•	we have designed a substantially-reduced capital investment program, with flexibility allowing us to respond to changing commodity price conditions in 2016;

•	we plan to defer certain activities to protect our strong liquidity position and expect the capital investment program to be more closely aligned with cash flow;

•	we have established a commodity price hedging program for 2016; and

•	we have robust liquidity of $5.0 billion at December 31, 2015 and ability to access capital markets.

•	net loss of $2.4 billion, as compared with net income of $1.2 billion for 2014;

•	net gain on commodity derivative instruments of $501 million (including $508 million non-cash loss), as compared with $976 million net gain (including $947 million non-cash gain) for 2014;

•	dry hole expense of $266 million, as compared with $226 million for 2014;

•	reduced lease operating expense of $4.43 per BOE, as compared with $5.58 per BOE for 2014, a reduction of 21%;

•	reduced general and administrative expense of $3.11 per BOE, as compared with $4.73 per BOE for 2014, a reduction of 34%;

•	asset impairment charges of $533 million, as compared with $500 million for 2014;

•	goodwill impairment charge of $779 million;

•	diluted loss per share of $6.07, as compared with diluted earnings per share of $3.27 for 2014;

•	cash flows provided by operating activities of $2.1 billion, as compared with $3.5 billion in 2014; and

•	capital expenditures, excluding Rosetta Merger, of $2.9 billion, as compared with $5.0 billion in 2014.

•	net cash proceeds of $1.1 billion received from public offering of shares of common stock;

•	extension of Credit Facility maturity date to August 27, 2020; and

•	cash dividend repatriation of $858 million from foreign operations.

•	cash balance of $1.0 billion, as compared with $1.2 billion at December 31, 2014;

•	total liquidity of $5.0 billion, as compared with $5.2 billion at December 31, 2014; and

•	ratio of debt-to-book capital of 43%, as compared with 38% at December 31, 2014.

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•	completion of the Rosetta Merger;

•	acquisition of a non-operated 20% working interest in Block 54 offshore Suriname;

•	sale of certain non-core onshore US properties, generating net proceeds of $151 million;

•	farm-out of a portion of our interest in Block 12 offshore Cyprus for total consideration of $165 million, $125 million of which was received in January 2016; and

•	sale of our 47% interest in the Alon A and Alon C licenses offshore Israel, which include Karish and Tanin natural gas discoveries, for total transaction value of $73 million ($67 million for asset consideration and $6 million from adjustment of costs), which closed in January 2016.

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•	commodity prices, which, if subject to further decline, could result in current production becoming uneconomic;

•	overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;

•	the reduced level of horizontal drilling activity onshore US and the decline in DJ Basin legacy vertical well production;

•	timing of start-up of a low pressure line-loop system, performance of gathering and processing infrastructure, capacity constraints of midstream facilities serving those wells, offset by additional capacity from new facilities, and occurrence of other events which impact capacity constraints of midstream facilities serving our DJ Basin wells;

•	timing of start-up of the Gunflint project (deepwater Gulf of Mexico) and Alba compression project (offshore Equatorial Guinea);

•	Israeli demand for electricity, which affects demand for natural gas as fuel for power generation and industrial market growth, and which is impacted by unseasonable weather;

•	conversion of Israeli electricity portfolio from coal to natural gas;

•	potential for exports of natural gas to Egypt and Jordan;

•	variations in West Africa crude oil and condensate sales volumes due to potential Aseng FPSO downtime and timing of liftings, and variations in natural gas sales volumes related to potential downtime at the methanol, LPG and/or LNG plants;

•	natural field decline in the deepwater Gulf of Mexico and offshore Equatorial Guinea;

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•	overall performance from onshore US wells;

•	potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico, or winter storms and flooding impacting onshore US operations;

•	reliability of support equipment and facilities and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or mid-stream processing;

•	pending Alba and Alen field unitizations in West Africa;

•	potential drilling and/or completion permit delays due to future regulatory changes; and

•	potential purchases of producing properties or divestments of non-core operating assets.

•	commodity prices, including price realizations on specific crude oil, natural gas and NGL production;

•	operating and development costs and the ability to achieve material supplier price reductions;

•	production, drilling, delivery commitments or other contractual obligations;

•	permitting activity in the deepwater Gulf of Mexico;

•	drilling results;

•	CONSOL Carried Cost Obligation (See Liquidity and Capital Resources – Off-Balance Sheet Arrangements);

•	property acquisitions and divestitures;

•	exploration activity;

•	cash flows from operations;

•	indebtedness levels;

•	availability of financing or other sources of funding;

•	potential legislative or regulatory changes regarding the use of hydraulic fracturing;

•	potential changes in the fiscal regimes of the US and other countries in which we operate; and

•	impact of new laws and regulations on our business practices.

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(1)

Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for US natural gas and NGLs are significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity.

(2)	Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.

(3)	Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Income from Equity Method Investees, below.

•	a 51% decrease in total consolidated average realized prices primarily due to the decline in global crude oil prices that began in the second half of 2014 and continued in 2015;

•	decrease in sales volumes due to planned downtime and maintenance as well as natural field decline in the deepwater Gulf of Mexico and the Aseng field, offshore Equatorial Guinea; and

•	decrease in sales volumes due to the sale of our China assets at the end of second quarter 2014;

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•	higher sales volumes of 7 MBbl/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;

•	sales volumes of 7 MBbl/d contributed by our recently-acquired Eagle Ford Shale and Permian Basin assets; and

•	start up of the deepwater Gulf of Mexico Rio Grande development in fourth quarter 2015 which contributed 2 MBbl/d.

•	a 9% decrease in total consolidated average realized prices primarily due to the NYMEX WTI crude oil price decline between June and December 2014, with a similar Brent crude oil price decline; and

•	lower sales volumes due to the sale of our China assets at the end of second quarter 2014 and the sale of certain North Sea assets during 2013;

•	higher sales volumes of 4 MBbl/d in the DJ Basin primarily attributable to our horizontal drilling programs; and

•	higher sales volumes of 2 MBbl/d in West Africa primarily due to the timing of crude oil and condensate liftings.

•	a 28% decrease in total consolidated average realized natural gas prices, including a 46% decrease in US average realized prices primarily due to oversupply; and

•	a widening of location basis differentials in the Marcellus Shale due to an oversupply of natural gas in the region which lowered the price we received;

•	higher sales volumes of 28 MMcf/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;

•	higher sales volumes of 131 MMcf/d in the Marcellus Shale primarily attributable to well completion and infrastructure development;

•	sales volumes of 58 MMcf/d contributed by our recently-acquired Eagle Ford Shale and Permian Basin assets; and

•	record sales volumes from the Tamar field, offshore Israel, which contributed 21 MMcf/d, in response to higher power generation needs;

•	higher sales volumes of 123 MMcf/d in the Marcellus Shale primarily attributable to our horizontal drilling program and continued ramp-up of activity;

•	higher sales volumes of 22 MMcf/d in the Eastern Mediterranean due to a full year of production from the Tamar field; and

•	a 14% increase in total consolidated average realized prices primarily due to increased demand from cooler weather earlier in 2014 and higher-than-expected inventory withdrawals in the US during the first quarter of 2014, which increased the market price in our producing areas;

•	lower sales volumes due to non-core onshore US properties divested during 2013 and 2014.

•	a 68% decrease in total consolidated average realized NGL prices, which are closely linked to the NYMEX WTI crude oil price decline, particularly in the Marcellus Shale;

•	higher sales volumes of 2 MBbl/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;

•	higher sales volumes of 5 MBbl/d in the Marcellus Shale primarily attributable to well completion and infrastructure development; and

•	sales volumes of 9 MBbl/d contributed by our recently-acquired Eagle Ford Shale and Permian Basin assets.

•	higher sales volumes of 3 MBbl/d in the DJ Basin, due to increased horizontal drilling activity; and

•	higher sales volumes of 4 MBbl/d in the Marcellus Shale, due to a full year of production from the wet gas acreage;

•	a 10% decrease in total consolidated average realized NGL prices, which are closely linked to the NYMEX WTI crude oil price declines between June and December 2014.

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(1)	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

(2)	Other International, Corporate includes the North Sea (in 2014 and 2015), China (through June 30, 2014) and corporate expenditures.

(3)	Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.

•	decrease of $17 million from sales of non-core onshore US properties in 2014;

•	decrease of $17 million due to the sale of our China assets at the end of second quarter 2014;

•	decrease of $15 million in deepwater Gulf of Mexico due to cessation of operations at South Raton, natural field decline and cost reduction initiatives;

•	decrease of $15 million offshore West Africa due to cost reduction initiatives and lower production;

•	decrease of $6 million in offshore Israel due to cost reduction initiatives; and

•	decrease of $9 million in other international/corporate due to cost reduction initiatives;

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•	increase of $38 million attributable to our recently-acquired Eagle Ford Shale and Permian Basin assets; and

•	increase of $11 million in the Marcellus Shale due to increased production.

•	increases of $63 million in the DJ Basin and $5 million in the Marcellus Shale due to increased development activity resulting in higher production;

•	increase of $41 million offshore Equatorial Guinea primarily driven by a full year of labor and FPSO expense resulting from the start up of the Alen field during the second half of 2013;

•	increase of $7 million offshore Israel primarily driven by a full year of expense for the Tamar field, which began producing at the end of first quarter 2013; and

•	increase of $15 million other international and corporate due to inclusion of North Sea in continuing operations during 2014, which was included in discontinued operations in 2013;

•	decrease of $45 million due to the acquisition of the Neptune facility in deepwater Gulf of Mexico;

•	decrease of $10 million from sales of non-core onshore US properties in 2014;

•	decrease of $8 million from the sale of our China assets at the end of second quarter 2014; and

•	decrease of $1 million from natural field decline from the Mari-B field, offshore Israel.

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(1)	West Africa includes Equatorial Guinea, Cameroon and Gabon.

(2)	Eastern Mediterranean includes Israel and Cyprus.

(3)	Other International, Corporate includes the Falkland Islands, Suriname and other new ventures and corporate expenditures.

(4)	Includes unproved leasehold amortization expense of $43 million in 2015, $43 million in 2014, and $30 million in 2013.

•	US dry hole cost includes amounts related to northeast Nevada exploration efforts which we elected to discontinue after assessing commercial viability in the current commodity price environment;

•	West Africa dry hole cost includes the Cheetah well (offshore Cameroon) and Other International dry hole cost includes the Humpback well (offshore Falkland Islands), neither of which identified commercial quantities of hydrocarbons; and

•	salaries and related expenses for corporate exploration and new ventures personnel.

•	dry hole cost related to the following exploratory wells which did not locate commercial quantities of hydrocarbons: Comanche Plains (onshore US); Bright (deepwater Gulf of Mexico); Madison (deepwater Gulf of Mexico); and Scotia (offshore Falkland Islands);

•	seismic expense related to the acquisition of 3D seismic data in the deepwater Gulf of Mexico, Equatorial Guinea, and Falkland Islands; and

•	salaries and related expenses for corporate exploration and new ventures personnel.

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(1)	DD&A expense includes accretion of discount on asset retirement obligations of $43 million in 2015, $36 million in 2014, and $26 million in 2013.

(2)	Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.

•	increase of $332 million in the DJ Basin and Marcellus Shale due to higher sales volumes and a reduction in proved reserves at year end primarily due to downward price revisions;

•	increase of $93 million related to our recently-acquired Eagle Ford Shale and Permian Basin assets;

•	increase of $55 million related to the Rio Grande development, deepwater Gulf of Mexico, which began producing in 2015;

•	increase in Equatorial Guinea due to a reduction in proved reserves at year end primarily due to downward price revisions; and

•	increase due to record sales volumes from the Tamar field, offshore Israel;

•	decrease of $92 million in the deepwater Gulf of Mexico due to planned downtime and maintenance and proved reserves additions; and

•	decrease due to the sale of our China assets during 2014.

•	higher sales volumes associated with increased development activity in the DJ Basin and the Marcellus Shale accounted for increases of $109 million and $95 million, respectively;

•	increase of $15 million in the deepwater Gulf of Mexico due to a full year of production for a new well at Ticonderoga and the addition of the Neptune spar at Swordfish;

•	increase of $38 million offshore Equatorial Guinea primarily due to a full year of production at the Alen field;

•	increase of $15 million due to a full year of production at the Tamar field, offshore Israel;

•	increase of $11 million due to North Sea properties reclassified to continuing operations for 2014; and

•	increase of $16 million associated with corporate assets;

•	decrease of $32 million due to sales of non-core onshore US properties in 2014 and 2013;

•	decrease of $49 million from natural field decline at the Mari-B, Noa and Pinnacles fields, offshore Israel; and

•	decrease of $35 million due to sale of China assets in 2014.

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(1)	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

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(1)	Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.

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changes for the year ended December 31, 2015 include negative revisions of 307 MMBoe due to lower commodity prices, downward revisions of 9 MMBoe and 5 MMBoe for the DJ Basin and Eagle Ford Shale, respectively, primarily due to current drilling and development plans in the DJ Basin and expected reserve recovery from existing producing wells in the Eagle Ford Shale, and downward revisions of 3 MMBoe due to natural field decline from the Mari-B field, offshore Israel; offset by positive performance revisions of 81 MMBoe for the Marcellus Shale, 17 MMBoe for the Permian Basin and 10 MMBoe for Alba field;

•	changes for the year ended December 31, 2014 included positive performance revisions of 18 MMBoe for the Marcellus Shale, 4 MMBoe for deepwater Gulf of Mexico, 4 MMBoe for Alba field, and 3 MMBoe for the Tamar field; offset by a downward revision of 8 MMBoe for the DJ Basin primarily due to planned reduction in pace of drilling activity due to lower commodity prices; and

•	changes for the year ended December 31, 2013 included positive performance revisions of 48 MMBoe for the DJ Basin and Marcellus Shale, 11 MMBoe for the Alba field, and 21 MMBoe for the Tamar field; and positive price revisions of 13 MMBoe due to higher commodity prices.

•	changes for the year ended December 31, 2015 include increases of 86 MMBoe in the DJ Basin and 14 MMBoe in the Marcellus Shale associated with our horizontal drilling programs;

•	changes for the year ended December 31, 2014 included increases of 47 MMBoe in the DJ Basin, 62 MMBoe in the Marcellus Shale, and 10 MMBoe deepwater Gulf of Mexico primarily attributable to sanction of the Dantzler development. The decrease in the DJ Basin changes from prior years is primarily due to the reduced pace of drilling activity in response to the lower commodity price outlook; and

•

changes for the year ended December 31, 2013 included increases of 130 MMBoe in the DJ Basin, 61 MMBoe in the Marcellus Shale, 18 MMBoe deepwater Gulf of Mexico primarily attributable to the sanction of the Big Bend and Gunflint developments, 8 MMBoe in Equatorial Guinea attributable to the Alba and Aseng fields, 30 MMBoe in Israel attributable to the discovery and sanction of the Tamar Southwest field, and 2 MMBoe associated with other development programs.

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•	the sale of non-core onshore US assets in 2015;

•	the sale of non-core onshore US and China assets in 2014; and

•	the sale of non-core onshore US and North Sea assets and the net impact of the DJ Basin acreage exchange in 2013.

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(1)	See Credit Facility, below.

(2)	Total debt includes capital lease and other obligations and excludes unamortized debt discount, premium, and issuance costs.

(3)	We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized premium/discount and unamortized debt issuance costs, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.

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(1)	Proved property acquisition cost relates to proved properties acquired in the Rosetta Merger. See Item 8. Financial Statements and Supplementary Data - Note 3. Merger, Acquisitions and Divestitures.

(2)

Unproved property acquisition cost for 2015 primarily relates to unproved properties acquired in the Rosetta Merger. See Item 8. Financial Statements and Supplementary Data - Note 3. Merger, Acquisitions and Divestitures. Additionally, unproved property acquisition cost for 2015 includes $49 million in the DJ Basin, $60 million in the Marcellus Shale, and $10 million and $5 million for costs incurred after the Rosetta Merger in the Permian Basin and Eagle Ford Shale, respectively.

(3)	2015 includes gathering and processing assets acquired in the Rosetta Merger. See Item 8. Financial Statements and Supplementary Data - Note 3. Merger, Acquisitions and Divestitures.

(4)	We own a 50% interest in CONE Gathering which is accounted for using the equity method. CONE Gathering constructs, owns and operates gathering lines and facilities related to the Marcellus Shale development.

(5)	Relates to estimated construction in progress on onshore US assets.

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•	$1.8 billion net increase in debt;

•	$291 million decrease in shareholders' equity from dividends paid; and

•	$2.4 billion decrease in shareholders' equity from current year net loss.

(1)	Long-term debt excludes our capital lease and other obligations. Amounts do not include impact of debt refinancing activities subsequent to year end. See Item 8. Financial Statements and Supplementary Data – Note 10. Long-Term Debt.

(2)	Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2015. See Item 8. Financial Statements and Supplementary Data – Note 10. Long-Term Debt.

(3)	Annual capital lease payments, net to our interest, exclude regular maintenance and operational costs. See Item 8. Financial Statements and Supplementary Data – Note 10. Long-Term Debt.

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(4)

Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to procure drilling rigs, such as the Atwood Advantage drill ship used in our Gulf of Mexico operations, and other related equipment for exploratory and development drilling activities. See Counterparty Credit Risk, above, and Item 8. Financial Statements and Supplementary Data – Note 18. Commitments and Contingencies.

(5)

Purchase obligations represent our working interest share of contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. See Counterparty Credit Risk, above, and Item 8. Financial Statements and Supplementary Data – Note 18. Commitments and Contingencies.

(6)	Transportation and gathering obligations represent minimum charges for firm transportation and gathering agreements related to our production. See Items 1. and 2. Business and Properties – Delivery Commitments. See Item 8. Financial Statements and Supplementary Data – Note 18. Commitments and Contingencies.

(7)	Operating lease obligations represent non-cancelable leases for office buildings and facilities and oil and gas operations equipment used in our daily operations. Amounts have not been discounted. See Item 8. Financial Statements and Supplementary Data – Note 18. Commitments and Contingencies.

(8)	The table excludes deferred compensation liabilities of $217 million and accrued benefit costs of $29 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data – Note 12. Stock-Based and Other Compensation Plans.

(9)	Asset retirement obligations are discounted. See Item 8. Financial Statements and Supplementary Data – Note 9. Asset Retirement Obligations.

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(1)	Amounts reflect impact of 2-for-1 stock split which occurred during second quarter 2013.

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•	Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.

•	Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.

•	Level 3 measurements are fair value measurements which use unobservable inputs.

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(1)	Amount represents expenses associated with the relocation of our Ardmore, Oklahoma office to our corporate headquarters in Houston and other organizational activities.

(2)	Amount represents the day rate cost associated with drilling rigs under contract, but not currently being utilized in our US onshore drilling programs.

(3)	Amount includes reclassification of the actuarial loss from AOCL related to the re-measurement and termination of our defined benefit pension plan to net income (loss).

(4)	Amount represents expenses associated with the completion of the Rosetta Merger. See Note 3. Merger, Acquisitions and Divestitures.

(5)	Amount represents lower of cost or market adjustment to materials and supplies inventory. See Note 13. Fair Value Measurements.

(6)	Amounts represent increases (decreases) in the fair values of shares of our common stock held in a rabbi trust and mutual funds.

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•	45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea;

•	28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas processing plant in Equatorial Guinea;

•	50% interest in CONE Gathering LLC (CONE Gathering), which owns and operates natural gas gathering facilities servicing our joint venture properties in the Marcellus Shale; and

•	32% interest in CONE Midstream Partners, LP (CONE Midstream), which constructs, owns and operates natural gas gathering and other midstream energy assets in support of our Marcellus Shale joint venture activities.

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(1)	We traditionally enter into a hedge contract term of one year. For 2016 and 2017 we have entered into various derivative hedging arrangements with a contract term of six months resulting in non-uniform annual volumes and weighted average prices.

(2)	We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced non-cash swap structure, we sold call options to the applicable counterparty to receive the above market terms.

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(1)

We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend for an additional 12-month period. Options covering a notional volume of 30,000 MMBtu/d are exercisable on December 22 and 23, 2016. If the counterparties exercise all such options, the notional volume of our existing natural gas derivative contracts will increase by 30,000 MMBtu/d at an average price of $3.50 per MMBtu for each month during the period January 1, 2017 through December 31, 2017.

(2)	Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.

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Expected term   The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date.

•

Expected volatility   The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term.

•	Risk-free rate  The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant.

•	Dividend yield  The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three-year period ended prior to the date of grant.

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(1)	See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy.

(2)	Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.

(1)	See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy.

(2)	Amount represents net book value at the date of assessment.

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(1)	Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations. No floating rate debt was outstanding at December 31, 2015 or December 31, 2014.

(1)	For the year ended December 31, 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss from continuing operations. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive.

(2)	The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015.

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(1)	Other International includes China (through June 2014), the North Sea and Israel.

(2)	The 2013 US revisions were primarily associated with positive performance revisions to our DJ Basin and Marcellus Shale programs as well as 2 MMBbls of positive price revisions. Equatorial Guinea revisions are associated with positive performance revisions to the Alba field.

(3)	The 2013 increase in US reserves included an increase of 89 MMBbls in the DJ Basin and 9 MMBbls from Marcellus Shale development as well as 15 MMBbls in the deepwater Gulf of Mexico from sanctioned development projects. The increase in Equatorial Guinea was attributable to future infill development at the Alba field. The increase to Other International included 1 MMBbls in China.

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(4)	The 2015 increase is attributable to reserves acquired in the Rosetta Merger.

(5)	In 2013, sales include divestitures of non-core, onshore US and North Sea assets as well as the net impact of the DJ Basin acreage exchange.

(6)	Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2015, 2014, 2013.

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(1)	In accordance with the terms of the Israel Natural Gas Framework, we will be required to reduce our ownership in the Tamar field to 25% within six years. See Items 1. and 2. Business and Properties – Update on Israel – Israel Natural Gas Framework.

(2)	Other International includes China (through June 2014) and the North Sea. See Note 3. Merger, Acquisitions and Divestitures.

(3)	The 2013 US revisions were primarily associated with positive performance revisions to our DJ Basin and Marcellus Shale programs as well as 68 Bcf of positive price revisions. Equatorial Guinea revisions are associated with positive performance revisions to the Alba field. Israel revisions are primarily associated with positive performance revisions to the Tamar field.

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(4)

The 2013 increase in US reserves included an increase of 250 Bcf in the DJ Basin and 317 Bcf from Marcellus Shale development as well as 18 Bcf in the deepwater Gulf of Mexico primarily from sanctioned development projects. Increases in Equatorial Guinea are attributable to future infill development at the Alba and Alen fields. Increases to Israel are due to discovery and sanction of the Tamar Southwest field.

(5)	The 2013 increase is attributable to the acquisition of additional acreage in the Marcellus Shale and other onshore US locations.

(6)	In 2013, sales include divestitures of non-core, onshore US and North Sea assets as well as the net impact of the DJ Basin acreage exchange.

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(1)	The 2015 US revisions are primarily associated with negative price revisions of 44 MMBbls to our onshore programs due to a decline in the 12-month average price, offset by a positive revision from our Marcellus Shale program due to positive well performance.

(2)	The 2013 additions in US reserves included an increase of 19 MMBbls in the DJ Basin and 8 MMBbls from Marcellus Shale development.

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(1)	Other International includes the North Sea, China (through June 30, 2014), Cameroon, Gabon, Sierra Leone (which we exited in 2015), Cyprus, Nicaragua (which we exited in 2015), Falkland Islands, Suriname, Corporate and other new ventures. See Note 3. Merger, Acquisitions and Divestitures.

(2)	Production costs consist of lease operating expense, production and ad valorem taxes, transportation expense, and general and administrative expense supporting oil and gas operations.

(3)

Income tax expense is based upon respective corporate statutory tax rates. During 2015, 2014 and 2013, we incurred exploration expense in currently non-commercial other international locations; therefore, no tax benefit was included in income tax expense associated with Other International as we could not conclude it was more likely than not that some portion or all of the deferred tax assets would be realized.

(4)	Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments, corporate overhead and interest costs. See Note 8. Derivative Instruments and Hedging Activities.

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(1)	Costs incurred include capitalized and expensed items.

(2)	Other International includes the North Sea, China (through June 30, 2014), Cameroon, Gabon, Sierra Leone, Cyprus, Nicaragua, Falkland Islands and Suriname. See Note 3. Merger, Acquisitions and Divestitures.

(3)	2015 proved and unproved property acquisitions include amounts allocated from the Rosetta Merger. See Note 3. Merger, Acquisitions and Divestitures.

(4)	2015 exploration costs include drilling and completion of $4 million in the DJ Basin, $22 million in the deepwater Gulf of Mexico, $1 million in Equatorial Guinea and $4 million in Cyprus.

(5)	Worldwide development costs include amounts spent to develop PUDs of approximately $1.5 billion in 2015, $2.0 billion in 2014, and $1.0 billion in 2013.

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(1)	Unproved oil and gas property cost at December 31, 2015 include previous acquisition costs of $1.2 billion related to the Eagle Ford Shale and Permian Basin properties and $566 million related to the Marcellus Shale.

(2)	Proved oil and gas properties at December 31, 2015 include asset retirement costs of $864 million and exclude assets held for sale of $67 million related to the Karish and Tanin natural gas discoveries offshore Israel.

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(1)	In accordance with the Israel Natural Gas Framework, we will be required to reduce our ownership in the Tamar field to 25% within six years. See Items 1. and 2. Business and Properties – Update on Israel – Israel Natural Gas Framework.

(2)	Other International includes China (through June 30, 2014) and the North Sea. See Note 3. Merger, Acquisitions and Divestitures.

(3)	The standardized measure of discounted future net cash flows does not include cash flows relating to anticipated future methanol sales.

(4)	Production costs include lease operating expense, production and ad valorem taxes, transportation expense and general and administrative expense supporting crude oil and natural gas operations.

(5)	Future development costs include future abandonment costs for each location. Specifically, Other International future development costs as of December 31, 2014 primarily includes the MacCulloch field (North Sea) abandonment costs. See Note 9. Asset Retirement Obligations.

(6)	Future income tax expense includes the effect of statutory tax rates and the impact of tax deductions, tax credits and allowances relating to our proved reserves. For 2015, future income tax expense for Israel also includes the effect of estimated future profit levy taxes.

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(1)	Other International includes China (through June 2014) and the North Sea. See Note 3. Merger, Acquisitions and Divestitures.

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(1)	Decrease in 2015 is driven primarily by lower 12-month average commodity prices.

(2)	Purchase of minerals in 2015 is driven by reserves acquired in the Rosetta Merger.

(3)	Increase in 2015 is reflective of lower estimated future income tax expense primarily driven by lower 12-month average commodity prices. For 2015, future income tax expense for Israel includes the effect of estimated future profit levy taxes which partially offset the increase in future net cash flows.

(4)	Decrease in 2015 reflects revisions in our estimated timing of production and development activity.

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(1)	First quarter 2015 included the following:

•	$150 million gain on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $60 million (See Note 8. Derivative Instruments and Hedging Activities); and

•	$27 million property impairment charges (See Note 5. Asset Impairments).

•	$87 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $274 million (See Note 8. Derivative Instruments and Hedging Activities); and

•	$15 million property impairment charges (See Note 5. Asset Impairments).

•	$267 million gain on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $17 million (See Note 8. Derivative Instruments and Hedging Activities); and

•	$71 million of other operating expenses associated with the Rosetta Merger.

•	$171 million gain on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $157 million (See Note 8. Derivative Instruments and Hedging Activities);

•	$779 million goodwill impairment charge (See Note 4. Goodwill); and

•	$490 million property impairment charges (See Note 5. Asset Impairments).

(2)	First quarter 2014 included the following:

•	$75 million loss on commodity derivative instruments, including non-cash portion of the loss on commodity derivative instruments of $42 million (See Note 8. Derivative Instruments and Hedging Activities);

•	$97 million property impairment charges (See Note 5. Asset Impairments); and

•	$1 million pre-tax loss on sale of non-core assets (See Note 3. Merger, Acquisitions and Divestitures).

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•	$236 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $187 million (See Note 8. Derivative Instruments and Hedging Activities);

•	$34 million property impairment charges (See Note 5. Asset Impairments); and

•	$42 million pre-tax gain on sale of non-core assets (See Note 3. Merger, Acquisitions and Divestitures).

•	$385 million gain on commodity derivative instruments, including the non-cash portion of the gain on commodity derivative instruments of $397 million (See Note 8. Derivative Instruments and Hedging Activities);

•	$33 million property impairment charges (See Note 5. Asset Impairments); and

•	$30 million pre-tax gain on sale of non-core assets (See Note 3. Merger, Acquisitions and Divestitures).

•	$903 million gain on commodity derivative instruments, including the non-cash portion of gain on commodity derivative instruments of $779 million (See Note 8. Derivative Instruments and Hedging Activities);

•	$2 million pre-tax gain on sale of non-core assets (See Note 3. Merger, Acquisitions and Divestitures); and

•	$336 million property impairment charges (See Note 5. Asset Impairments).

(3)	The sum of the individual quarterly earnings (loss) may not agree with year-to-date earnings as each quarterly computation is based on the earnings for the individual quarter as reported with rounding applied.

(4)	The sum of the individual quarterly earnings (loss) per share amounts may not agree with year-to-date earnings per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of shares outstanding during that quarter.

(5)

Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while the Noble Energy shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculation for both the three month period ended December 31, 2014 and the year ended December 31, 2014 excludes deferred compensation gains of $17 million, net of tax.

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(3)	Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.

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