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•	our growth strategies;

•	our future results of operations;

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

•	our ability to make and integrate acquisitions;

•	our ability to successfully and economically explore for and develop crude oil, natural gas and natural gas liquids (NGLs) resources;

•	anticipated trends in our business;

•	market conditions in the oil and gas industry;

•	the impact of governmental fiscal regulation, including federal, state, local, and foreign host tax regulations, and/or terms, 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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•	United States, including the onshore DJ Basin, Permian Basin, Eagle Ford Shale, Marcellus Shale, and offshore deepwater Gulf of Mexico, as well as the consolidated accounts of Noble Midstream Partners LP (Noble Midstream Partners), which completed its initial public offering of common units in 2016;

•	Eastern Mediterranean, including offshore Israel and Cyprus;

•	West Africa, including offshore Equatorial Guinea, Cameroon, and Gabon; and

•	Other International and Corporate, including new ventures such as offshore the Falkland Islands, Suriname, and Newfoundland.

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•	positive revisions of 117 MMBoe related to our onshore US horizontal drilling programs and Alba field, offshore Equatorial Guinea, driven by increased well performance and/or lower operating or development costs in onshore US and the startup of the Alba B3 compression platform; and

•	extensions and other additions of 179 MMBoe related to our onshore US horizontal drilling programs due to successful expansion of our extended reach lateral well programs;

•	production volumes of 154 MMBoe;

•	negative revisions of 53 MMBoe that were commodity price driven; and

•	reduction of 77 MMBoe primarily due to our 3.5% reduction in ownership in Tamar, the impact of the Marcellus Shale acreage exchange, and other smaller onshore US divestitures.

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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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closed an acreage exchange agreement to receive approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco development area, located southwest of Wells Ranch. The exchange enhances our ability to develop the field by improving our contiguous acreage position, increasing our lateral length potential and optimizing our access to central gathering facilities;

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entered into an agreement to divest approximately 33,100 producing and undeveloped net acres in the Greeley Crescent area of Weld County, Colorado for $505 million, representing approximately 8% of our total DJ Basin acreage. We received proceeds of $486 million in 2016 and expect to receive the remaining proceeds in mid-2017. Proceeds received were applied to the field's basis with no recognition of gain or loss. As part of the transaction, all of the acreage in the Greeley Crescent IDP remains subject to dedications to Noble Midstream Partners for crude oil gathering, produced water services and fresh water services; and

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•	sold certain other producing and non-producing assets, generating net proceeds of $20 million, which were applied to the field basis, with no recognition of gain or loss.

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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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changes for the year ended December 31, 2016 include positive revisions of 43 MMBoe for the DJ Basin, 42 MMBoe for the Marcellus Shale, 11 MMBoe for the Permian Basin, 6 MMBoe for deepwater Gulf of Mexico, 5 MMBoe for other onshore US and 10 MMBoe for Alba field, offshore Equatorial Guinea, due to increased performance and/or lower development or operating costs; partially offset by negative revisions of 53 MMBoe due to lower commodity prices;

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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,

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•	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.

•	changes for the year ended December 31, 2016 include increases of 83 MMBoe in the DJ Basin, 42 MMBoe in the Marcellus Shale, 33 MMBoe in the Permian Basin and 21 MMBoe in the Eagle Ford Shale, all associated with our horizontal drilling programs;

•	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; and

•	changes for the year ended December 31, 2014 included increases of 48 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.

•	an increase of 4 MMBoe of NGL reserves primarily resulting from our Marcellus Shale acreage exchange in 2016; and

•	the acquisition of additional acreage, primarily in the Eagle Ford Shale and Permian Basin in Texas in 2015 in connection with the Rosetta Merger.

•	a reduction of 36 MMBoe in Israel driven by our 3.5% sale of Tamar working interest, divestment of 29 MMBoe in the Marcellus Shale driven by our asset exchange, and other smaller divestments in onshore US resulting in a reduction of 12 MMBoe in 2016;

•	the sale of onshore US assets in 2015; and

•	the sale of onshore US and China assets in 2014.

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•	53 MMBoe positive revisions primarily in the DJ Basin, Marcellus Shale and Permian Basin due to current drilling and development plans;

•	negative revisions of 21 MMBoe due to lower commodity prices.

•	76 MMBoe in the DJ Basin;

•	31 MMBoe in the Permian Basin;

•	19 MMBoe in the Eagle Ford Shale; and

•	40 MMBoe in the Marcellus Shale.

•	26 MMBoe in the DJ Basin;

•	1 MMBoe in the Permian;

•	25 MMBoe in the Eagle Ford Shale;

•	33 MMBoe in the Marcellus Shale;

•	13 MMBoe in deepwater Gulf of Mexico; and

•	70 MMBoe in the Alba Field, offshore Equatorial Guinea.

•	199 MMBoe in the DJ Basin;

•	70 MMBoe in the Permian Basin;

•	92 MMBoe in the Eagle Ford Shale; and

•	61 MMBoe in the Marcellus Shale.

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•	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

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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 expense.

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(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.

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

(1)	Undeveloped acreage excludes an exploration lease totaling approximately 55,000 gross (19,000 net) acres which expired in 2016. We are negotiating with the government of Equatorial Guinea to extend the lease.

(2)	Following completion of our geological assessment in 2016, we exited all licenses in the Falklands Islands, outside of License PL-001, which contains the Rhea prospect, thereby reducing our acreage position by approximately 10 million, gross, and 3 million, net, acres.

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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.

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•	the Ministry of Mines and Hydrocarbons, 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; and

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

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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;

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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 (RCRA), 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 or other long-lived assets;

•	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 obligations under throughput agreements if production is suspended;

•	reduction, or suspension, of our 2017 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.

•	declines in our stock price; and

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

•	global demand for crude oil, natural gas and NGLs as impacted by economic factors that affect gross domestic product growth rates of countries around the world;

•	global supply for crude oil, natural gas and NGLs as impacted by OPEC and Non-OPEC countries (e.g. US, Russia, Canada);

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

•	new technologies that promote fuel efficiency and reduce energy consumption;

•	developments in the global liquified natural gas (LNG) market, including exports from the US;

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•	geopolitical conditions and events, including generational leadership or regime changes, changes in government energy policies, including imposed price controls and/or product subsidies, or instability/armed conflict in hydrocarbon-producing regions;

•	fluctuations in US dollar exchange rates, the currency in which the world's crude oil trade is generally 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/infrastructure as well as refining capacity;

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

•	the effectiveness of worldwide conservation measures;

•	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.

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

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

•	render future exploration and development projects uneconomic.

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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 trade, foreign investment, taxation and business conduct;

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

•	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;

•	US and international monetary policies causing 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;

•	limit 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;

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•	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.

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

•	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;

•	harsh weather and rough seas offshore the Falkland Islands and Newfoundland, which could limit 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.

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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 crude oil and natural 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.

•	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 a development project, 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;

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•	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;

•	remote locations make it more difficult and time-consuming to transport personnel, equipment and supplies;

•	certain operating environments, such as offshore the Falkland Islands and Newfoundland, include harsh weather and rough seas which could limit seismic surveys and other exploration activities during certain periods;

•	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.

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•	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 in the Credit Agreement) 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 our industry;

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

•	changes in our debt credit ratings 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 (Revolving Credit Facility); and

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

•	large multi-national, integrated oil and gas companies;

•	state-controlled national oil companies;

•	US independent oil and gas companies;

•	US onshore midstream companies;

•	service companies engaging in exploration and production activities; and

•	private investing in oil and gas equity funds.

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

•	acquiring or increasing access to gathering, processing and transportation services and capacity;

•	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.

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•	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 and abandonment costs;

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

•	severance and excise taxes; and

•	workover and remedial costs.

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•	incorrect estimates or assumptions about reserves, exploration potential or potential drilling locations;

•	incorrect assumptions regarding future revenues, including future commodity prices and differentials, or regarding future development and operating costs;

•	incorrect assumptions regarding potential synergies and the overall costs of equity or debt;

•	difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and

•	unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.

•	current commodity prices;

•	laws and regulations impacting oil and gas operations in the areas where the assets are located;

•	willingness of the purchaser to assume certain liabilities such as asset retirement obligations;

•	our willingness to indemnify buyers for certain matters; and

•	delays in closing.

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

(2)	Goodwill was fully impaired at December 31, 2015. See Item 8. Financial Statements and Supplementary Data – Note 1. Summary of Significant Accounting Policies.

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•	Executive Summary;

•	Executive Overview;

•	Operating Outlook;

•	Results of Operations;

•	Liquidity and Capital Resources; and

•	Critical Accounting Policies and Estimates.

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•	integration of Rosetta Resources Inc., which expanded our portfolio with entry into two top-tier US Basins, the Eagle Ford Shale and Permian Basin;

•	additional Permian Basin bolt-on acquisitions;

•	improvement in the DJ Basin regulatory and legislative environment;

•	exchange of acreage in the DJ Basin which increased our contiguous acreage position; and

•	dissolution of the Marcellus Shale joint venture, providing increased flexibility and control over our investment.

•	project sanction readiness at Leviathan;

•	increased production with less capital investment;

•	improved returns with technology advancements and structural cost savings; and

•	delivery of major offshore projects on budget and on schedule.

•	proactive and strategic action to manage within cash flows;

•	strong liquidity position including cash on hand and unused borrowing capacity;

•	portfolio management and midstream strategy, which increase our future financial capacity;

•	reduction of our outstanding debt through cash on hand; and

•	maintenance of our investment grade credit rating.

•	crude oil, natural gas and NGL revenues of $3.4 billion, as compared with $3.1 billion for 2015;

•	net loss attributable to Noble Energy of $998 million, as compared with net loss of $2.4 billion for 2015;

•	net loss on commodity derivative instruments of $139 million (including $708 million non-cash loss), as compared with $501 million net gain (including $508 million non-cash loss) for 2015;

•	dry hole expense of $579 million, as compared with $266 million for 2015;

•	undeveloped leasehold impairment expense of $93 million, as compared with $21 million for 2015;

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•	reduced lease operating expense of $3.59 per BOE, as compared with $4.43 per BOE for 2015, a reduction of 19%;

•	reduced general and administrative expense of $2.64 per BOE, as compared with $3.11 per BOE for 2015, a reduction of 15%;

•	asset impairment expense of $92 million, as compared with $533 million for 2015;

•	diluted loss per share attributable to Noble Energy of $2.32, as compared with diluted loss per share of $6.07 for 2015;

•	cash flows provided by operating activities of $1.4 billion, as compared with $2.1 billion in 2015; and

•	capital expenditures of $1.6 billion, as compared with $2.9 billion, excluding the Rosetta Merger, in 2015.

•	net cash proceeds of $299 million received from issuance of Noble Midstream Partners common units, net of offering costs;

•	proceeds of $1.2 billion from asset sales; and

•	prepayment of $850 million of borrowings under our Term Loan Facility.

•	cash balance of $1.2 billion, as compared with $1.0 billion at December 31, 2015;

•	total liquidity of $5.2 billion, as compared with $5.0 billion at December 31, 2015; and

•	ratio of debt-to-book capital of 43%, as compared with 43% at December 31, 2015.

•	we have a high-quality, globally diversified portfolio of assets, focused on top-tier basins, and the majority of our assets are held by production, which provides investment optionality and flexibility;

•	we have exploration expertise which has led to numerous discoveries, in the deepwater Gulf of Mexico, Levant Basin offshore Eastern Mediterranean and the Douala Basin offshore West Africa, resulting in major development project opportunities;

•	we have operational and technical expertise which has led to our delivery of major development projects on schedule and within budget providing a competitive and financial advantage in our industry;

•	we have achieved substantial cost reductions (and are well-positioned on the global cost supply curve) impacting both operating expenses and capital expenditures;

•	we have designed a capital investment program, with flexibility allowing us to respond to changing commodity price conditions in 2017;

•	we have adjusted our quarterly dividend to 10 cents per common share; and

•	we have robust liquidity of $5.2 billion at December 31, 2016 and ability to access capital markets.

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•	commodity prices, which, if subject to 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;

•	Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and conversion of Israeli electricity portfolio from coal to natural gas;

•	timing of the divestiture of the remaining 7.5% working interest in the Tamar field which will lower our sales volumes;

•	potential growth in the Israeli natural gas export market;

•	timing of crude oil and condensate liftings impacting sales volumes in West Africa;

•	natural field decline in onshore US, deepwater Gulf of Mexico and offshore Equatorial Guinea;

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

•	reliability of support equipment and facilities, pipeline disruptions, and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or midstream processing;

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

•	impact of enhanced completion efforts for onshore US assets;

•	potential shut-in of US producing properties if storage capacity becomes unavailable;

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

•	potential purchases of producing properties or divestments of 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;

•	drilling results;

•	property acquisitions and divestitures;

•	exploration activity;

•	cash flows from operations;

•	indebtedness levels;

•	availability of financing or other sources of funding;

•	permitting activity in the deepwater Gulf of Mexico;

•	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

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(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.

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

•	higher sales volumes of 9 MBbl/d in the Eagle Ford Shale and Permian Basin primarily attributable to full year consolidation following the Rosetta Merger;

•	sales volumes from the Big Bend and Dantzler developments (deepwater Gulf of Mexico), which began producing fourth quarter 2015 and contributed 12 MBbl/d, net, collectively in 2016; and

•	start up of the deepwater Gulf of Mexico Gunflint development in July 2016 which contributed 3 MBbl/d;

•	a 10% 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 into 2016; and

•	decrease in sales volumes due to natural field decline at Aseng and Alen, offshore Equatorial Guinea.

•	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;

•	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.

•	higher sales volumes of 93 MMcf/d in the Marcellus Shale primarily attributable to well completion and infrastructure development;

•	higher sales volumes of 81 MMcf/d in the Eagle Ford Shale and Permian Basin primarily attributable to full year consolidation following the Rosetta Merger;

•	record sales volumes from the Tamar field, offshore Israel, which contributed an incremental 29 MMcf/d, in response to higher power generation needs; and

•	higher sales volumes offshore Equatorial Guinea due to the completion of the Alba B3 compression project.

•	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

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•	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 an incremental 21 MMcf/d, in response to higher power generation needs.

•	higher sales volumes of 14 MBbl/d in the Eagle Ford Shale and Permian Basin primarily attributable to a full year of production as well as increased development activity;

•	a 7% increase in total consolidated average realized prices, primarily due to higher spot prices in the Marcellus Shale; and

•	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;

•	slightly lower sales volumes in the Marcellus Shale due to the higher dry gas composition of wells that were brought online in 2016.

•	a 59% 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.

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(1)	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees and include expenses related to Noble Midstream Partners.

(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 $92 million onshore US, primarily in the DJ Basin and Marcellus Shale, and $27 million offshore Equatorial Guinea due to cost reduction initiatives, including lower equipment utilization and saltwater disposal costs;

•	increase of $74 million attributable to new production from onshore US and deepwater Gulf of Mexico development activities; and

•	increase of $38 million related to the acquisition of Eagle Ford Shale and Permian Basin production third quarter 2015.

•	decrease of $17 million from sales of non-strategic 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;

•	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.

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•	increase of $66 million related to higher production from our Marcellus Shale assets;

•	increase of $57 million related to change in mix of transportation methods used for our DJ Basin production;

•	increase of $49 million related to higher production from our Eagle Ford Shale assets acquired third quarter 2015; and

•	increase of $17 million related to production from our new deepwater Gulf of Mexico projects at Big Bend and Dantzler (which began producing fourth quarter 2015) and Gunflint (which began producing in July 2016).

•	increase of $81 million in the Marcellus Shale due to higher production and increased expenses due to service contracts with CONE Gathering;

•	increase of $33 million due to recently-acquired Eagle Ford Shale and Permian Basin properties; and

•	increase of $12 million in the DJ Basin due to the May 2015 commencement of Tallgrass pipeline, which transports DJ Basin crude oil;

•	$8 million decrease due to the sale of non-strategic onshore US, China and North Sea properties in 2014.

(1)	Eastern Mediterranean includes Israel and Cyprus.

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

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

(4)	For a discussion of 2016 dry hole cost, see Items 1. and 2. Business and Properties – International – West Africa and Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs.

(5)	Includes lease rental and other exploration expense.

•	leasehold impairment expense including the write-off of leases and licenses of $58 million for the deepwater Gulf of Mexico, $25 million for the Falkland Islands and $10 million for other onshore US;

•	dry hole cost including costs related to the Silvergate exploratory well, deepwater Gulf of Mexico, the Dolphin 1 natural gas discovery, offshore Israel, and certain discoveries offshore West Africa;

•	seismic expense relating to the acquisition of 3D seismic data in West Africa and other international areas;

•	other cost for onshore US including lease rentals primarily related to Permian Basin leases; and

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

•	leasehold impairment expense including the write-off of our northeast Nevada leases of $21 million;

•	US dry hole cost including 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 including the Cheetah well (offshore Cameroon) and Other International dry hole cost including 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.

(1)	DD&A expense includes accretion of discount on asset retirement obligations of $48 million in 2016, $43 million in 2015, and $36 million in 2014.

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

•	increase of $178 million related to higher sales volumes resulting from commencement of production from the Big Bend, Dantzler and Gunflint development projects in deepwater Gulf of Mexico in 2016 and 2015;

•	increase of $134 million related to the acquisition of Eagle Ford Shale and Permian Basin production third quarter 2015; and

•	$121 million related to the reduction in proved reserves in fourth quarter 2015 primarily due to downward price revisions in DJ Basin and Marcellus Shale;

•	an overall lower segment rate for offshore Equatorial Guinea due to the fluctuation in production from higher DD&A rate assets Aseng and Alen to lower DD&A rate asset Alba field.

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•	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.

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

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•	cash settlements (received) or paid relating to our crude oil and natural gas commodity derivative contracts, and

•	non-cash (increases) or decreases in the fair values of our crude oil and natural gas commodity derivative contracts.

•	$499 million contributed by crude oil contracts; and

•	$70 million contributed by natural gas contracts.

•	$582 million related to crude oil contracts; and

•	$126 million related to natural gas contracts.

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•	$755 million contributed by crude oil contracts entered into by Noble and $89 million contributed by crude oil contracts acquired in the Rosetta Merger; and

•	$120 million contributed by natural gas contracts entered into by Noble, $27 million contributed by natural gas contracts acquired in the Rosetta Merger and $18 million contributed by NGL contracts acquired in the Rosetta Merger.

•	$423 million related to crude oil contracts;

•	$65 million related to natural gas contracts; and

•	$20 million related to NGL contracts.

•	$34 million contributed by crude oil contracts;

•	$5 million paid for natural gas contracts.

•	$863 million related to crude oil contracts; and

•	$84 million related to natural gas contracts.

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

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(1)	Total cash includes cash and cash equivalents of almost $1.2 billion, which includes $57 million cash relating to Noble Midstream Partners, as well as restricted cash of $30 million related to the Permian Basin property acquisition that closed in January 2017.

(2)	Excludes $350 million available to be borrowed under Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy, as of December 31, 2016. See Revolving Credit Facilities, below.

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

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

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(1)	Proved property acquisition costs for 2015 relates to proved properties acquired in the Rosetta Merger. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions, Divestitures and Merger.

(2)

2016 unproved property acquisition costs relate to the termination of the Marcellus Shale joint development. Costs in 2015 primarily relate to unproved properties acquired in the Rosetta Merger. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions, Divestitures and Merger. 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)	2016 includes expenditures of Noble Midstream Partners, and 2015 includes midstream assets acquired in the Rosetta Merger. See Item 8. Financial Statements and Supplementary Data - Note 3. Acquisitions, Divestitures and Merger.

(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 onshore US assets.

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•	$1.0 billion net decrease in debt;

•	$172 million decrease in shareholders' equity from dividends paid; and

•	$1.0 billion decrease in shareholders' equity from current year net loss.

(1)	Long-term debt excludes our capital lease and other obligations. See Item 8. Financial Statements and Supplementary Data – Note 10. Long-Term Debt.

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(2)	Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2016. 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.

(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, 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 $218 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.

(10)	Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2016. See Item 8. Financial Statements and Supplementary Data – Note 8. Derivative Instruments and Hedging Activities.

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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)

Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of $50 million and $14 million for the years ended December 31, 2015 and 2014, respectively, have been reclassified to transportation and gathering expense to conform to the current presentation.

(2)	See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

(3)

Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. Prior year amounts of $33 million and $16 million for the years ended December 31, 2015 and 2014, respectively, were previously presented within transportation and gathering expense. These amounts have been reclassified to conform to the current presentation. See Note 18. Commitments and Contingencies.

(4)	Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance.

(5)	Includes gain related to the sale of 3.5% working interest in the Tamar field, offshore Israel. See Note 3. Acquisitions, Divestitures and Merger.

(6)	Amount represents expenses associated with organizational activities.

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(7)	Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 10. Long-Term Debt.

(8)	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).

(9)	Amounts represent a purchase price allocation adjustment in 2016 and merger expenses in 2015. See Note 3. Acquisitions, Divestitures and Merger.

(10)	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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•

entered an agreement to divest certain producing and non-producing properties covering approximately 33,100 net acres in the DJ Basin for proceeds of $505 million. We closed the sale on a portion of the properties in 2016, receiving proceeds of $486 million. We expect to close the sale of the remaining properties, which are classified as held for sale at December 31, 2016, and receive the remaining proceeds, subject to post-close adjustments, in mid-2017. Proceeds were applied to reduce field basis with no recognition of gain or loss.

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•	sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern Montana, and certain other smaller onshore US properties, generating total net proceeds of $152 million, a net loss of $23 million on the Bowdoin sale, and no further gain or loss recognized on the remaining transactions.

•	sold our 47% interest in the Alon A and Alon C licenses, offshore Israel, which included the Karish and Tanin fields, for a total sales price of $73 million ($67 million for asset consideration and $6 million from cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss.

•

sold a 3.5% working interest in the Tamar field, offshore Israel, in compliance with the terms of the Israel Natural Gas Framework, which requires us to reduce our ownership interest in Tamar to 25% by year-end 2021. The sales price totaled $431 million, and we received net cash proceeds of $316 million, after consideration of timing and tax adjustments, at closing. Proceeds were ratably applied to the field's basis and resulted in the recognition of a $261 million gain.

•	received proceeds of $131 million related to a farm-out agreement for a 35% interest in Block 12, offshore Cyprus, which includes the Aphrodite natural gas discovery. We received the remaining proceeds of $40 million in January 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss.

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•	1,527,584 common units, representing a 4.8% limited partner interest in Noble Midstream Partners;

•	15,902,584 subordinated units, representing an approximate 50.0% limited partner interest in Noble Midstream Partners;

•	incentive distribution rights in Noble Midstream Partners; and

•	the right to receive a cash distribution from Noble Midstream Partners.

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

•	33.5% interest in CONE Midstream Partners, LP (CONE Midstream), a public master limited partnership, which constructs, owns and operates natural gas gathering and other midstream energy assets in support of our Marcellus Shale activities;

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

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

(1)	CONE Investments include CONE Midstream and CONE Gathering.

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(1)	We traditionally enter into a hedge contract term of one year. For 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.

(3)	We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.

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(1)	We traditionally enter into a hedge contract term of one year. For 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 certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.

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(1)	Amounts for NGLs relate to commodity derivative instruments, acquired in the Rosetta Merger, which expired as of December 31, 2015.

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(1)	Represents senior notes assumed in the Rosetta Merger. See Note 3. Acquisitions, Divestitures and Merger.

(2)	Debt premium is attributable to senior notes assumed in the Rosetta Merger.

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•	in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00%; or

•	in the case of London interbank offered rate (LIBOR) borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.

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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.

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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 net book value at the date of assessment.

(1)	Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.

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(1)	For the years ended December 31, 2016 and 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. 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 for the year ended December 31, 2015 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)	Includes sales to Shell Trading (US) Company and/or Shell International Trading and Shipping Limited.

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(1)	Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 10. Long-Term Debt.

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

(2)	The 2014 US revisions were primarily associated with positive performance revisions to our Marcellus Shale program and our deepwater Gulf of Mexico Swordfish field, offset by DJ Basin negative revisions due to a revised drilling plan in response to the current commodity price environment.

(3)	The 2014 increase in US reserves included an increase of 21 MMBbls in the DJ Basin and 2 MMBbls from Marcellus Shale development as well as 7 MMBbls in the deepwater Gulf of Mexico due to sanction of the Dantzler development project.

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

(5)	In 2014, we sold our China assets.

(6)	Equatorial Guinea production includes sales from the Alba LPG plant of approximately 3 MMBbl in each of the years 2016, 2015, and 2014.

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(1)	In accordance with the terms of the Israel Natural Gas Framework, we are required to reduce our ownership in the Tamar field to 25% by year-end 2021. During 2016, we reduced our ownership to 32.5% through a sale.

(2)	Other International includes China.

(3)

The 2014 US revisions were primarily associated with a positive performance revision to our Marcellus Shale program offset by a negative revision to our DJ Basin program due to a revised drilling program in response to the current commodity price environment. 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 2014 increase in US reserves included an increase of 110 Bcf in the DJ Basin and 309 Bcf from Marcellus Shale development as well as 14 Bcf in the deepwater Gulf of Mexico.

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

(6)	In 2014, we sold onshore US and China assets.

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(1)	The 2015 US revisions were primarily associated with negative price revisions of 44 MMBbls related 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 2014 additions in US reserves included an increase of 8 MMBbls in the DJ Basin and 8 MMBbls from Marcellus Shale development.

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(1)	Other International includes the North Sea (through 2014), China (through June 30, 2014) and new ventures.

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

(3)	Equatorial Guinea exploration expense includes $468 million for the write off of costs associated with certain discoveries. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

(4)	Asset impairments relate to certain Leviathan development concepts costs. See Note 5. Asset Impairments.

(5)

Income tax expense is based upon respective corporate statutory tax rates. During 2016, 2015, and 2014, 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.

(6)	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) and new ventures. See Note 3. Acquisitions, Divestitures and Merger.

(3)	2016 unproved property acquisition costs relate to the termination of the Marcellus Shale joint development. See Note 3. Acquisitions, Divestitures and Merger.

(4)	2016 exploration costs include drilling and completion of $1 million in the Marcellus Shale and $44 million in the deepwater Gulf of Mexico.

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(5)	Worldwide development costs include amounts spent to develop PUDs of approximately $656 million in 2016, $1.5 billion in 2015, and $2.0 billion in 2014.

(1)	Unproved oil and gas property cost at December 31, 2016 include previous acquisition costs of $1.2 billion related to the Eagle Ford Shale and Permian Basin properties and $758 million related to the Marcellus Shale.

(2)	Proved oil and gas properties at December 31, 2016 include asset retirement costs of $897 million and exclude assets held for sale of $18 million.

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(1)	In accordance with the Israel Natural Gas Framework, we are required to reduce our ownership in the Tamar field to 25% by year-end 2021. During 2016, we reduced our ownership to 32.5% through a sale. Therefore, 2016 amounts reflect a 32.5% working interest, while 2015 and 2014 amounts reflect a 36% working interest. See Note 3. Acquisitions, Divestitures and Merger.

(2)	Other International represents North Sea abandonment costs.

(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. 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 2016 and 2015, future income tax expense for Israel also includes the effect of estimated future profit levy taxes and changes to corporate income tax rates.

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(1)	Imbalance receivables and liabilities for 2015 and 2014 related primarily to onshore US assets which were sold in 2016.

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

(2)	Purchase of minerals in 2015 relates to reserves acquired in the Rosetta Merger.

(3)	The increase in 2015 reflects 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)	The decrease in 2015 reflects revisions in our estimated timing of production and development activity.

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•	$44 million gain on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $134 million (See Note 8. Derivative Instruments and Hedging Activities); and

•	$80 million gain on extinguishment of debt.

•	$151 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $295 million (See Note 8. Derivative Instruments and Hedging Activities); and

•	$25 million purchase price allocation adjustment related to Rosetta Merger (See Note 3. Merger, Acquisitions and Divestitures).

•	$81 million undeveloped leasehold impairment expense (See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs);

•	$55 million gain on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $77 million (See Note 8. Derivative Instruments and Hedging Activities).

•	$579 million dry hole costs included in exploration expense (See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs);

•	$87 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $201 million (See Note 8. Derivative Instruments and Hedging Activities); and

•	$92 million property impairment charges (See Note 5. Asset Impairments)

•	$150 million gain on commodity derivative instruments, including non-cash portion of 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 non-cash portion of 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 non-cash portion of 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 non-cash portion of loss on commodity derivative instruments of $157 million (See Note 8. Derivative Instruments and Hedging Activities);

•	$779 million goodwill impairment charge (See Note 1. Summary of Significant Accounting Policies); and

•	$490 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.

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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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