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•	our growth strategies;

•	our future results of operations;

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

•	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;

•	our ability to make and integrate acquisitions; and

•	access to resources.

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•	revisions of 135 MMBoe, including positive revisions of 105 MMBoe driven by performance related to the US onshore horizontal drilling programs and offshore Israel associated with the enhanced geologic modeling across the Tamar reservoir, as well as an increase of 30 MMBoe driven by positive price revisions;

•	extensions, discoveries and other additions of 736 MMboe, including additions of 551 MMBoe related to the sanction of the first phase of development of the Leviathan natural gas project, as well as extensions of 185 MMBoe related to US onshore horizontal drilling programs due to successful expansion of our extended reach lateral well programs;

•	acquisition of 57 MMBoe primarily related to the Clayton Williams Energy Acquisition;

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•	production volumes of 139 MMBoe; and

•	divestiture of reserves of 261 MMBoe, primarily due to the Marcellus Shale upstream divestiture and other smaller US onshore divestitures.

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(1)	Excludes the Araku-1 exploration well, offshore Suriname.

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•	completion of a produced water expansion project servicing the Wells Ranch IDP area;

•	completion of crude oil and produced water gathering systems servicing the Greeley Crescent IDP area;

•	completion of the connection from the CGF in the Delaware Basin to the Advantage Pipeline, which began allowing crude oil to flow from the completed facility to the Advantage Pipeline in third quarter 2017;

•	completion of the construction of two CGFs in the Delaware Basin; and

•	continued construction activities on expansion of our freshwater system servicing the Mustang IDP area and the commencement of construction of the backbone gathering infrastructure build-out, which is expected to be completed in early 2018.

•	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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•	positive price revisions of 30 MMBoe globally, as well as positive performance revisions of 49 MMBoe for the Tamar field, offshore Israel, 30 MMBoe for the Delaware Basin and 22 MMBoe for the Eagle Ford Shale, partially offset by abandonment cost increases for US onshore in 2017;

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•	positive revisions of 43 MMBoe for the DJ Basin, 42 MMBoe for the Marcellus Shale, 11 MMBoe for the Delaware Basin, and 10 MMBoe for the 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 in 2016; and

•	negative price revisions of 307 MMBoe, partially offset by positive performance revisions of 81 MMBoe for the Marcellus Shale and 17 MMBoe for the Delaware Basin in 2015.

•	increases primarily relate to 99 MMBoe in the DJ Basin and 77 MMBoe in the Delaware Basin as a result of enhanced completion techniques in our horizontal drilling programs and an increase of 551 MMBoe due to the sanction of the first phase of development at the Leviathan natural gas field in 2017;

•	increases of 83 MMBoe in the DJ Basin, 42 MMBoe in the Marcellus Shale, 33 MMBoe in the Delaware Basin and 21 MMBoe in the Eagle Ford Shale, all associated with our horizontal drilling programs in 2016; and

•	increases of 86 MMBoe in the DJ Basin and 14 MMBoe in the Marcellus Shale associated with our horizontal drilling programs in 2015.

•	an increase of 57 MMBoe in the Delaware Basin primarily as a result of the Clayton Williams Energy Acquisition in 2017; and

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

•	a reduction of 241 MMBoe related to the Marcellus Shale upstream divestiture, as well as 20 MMBoe associated with divestment of non-strategic US onshore assets in 2017;

•	a reduction of 36 MMBoe in Israel driven by our 3.5% sale of Tamar working interest, as well as a 29 MMBoe divestment in the Marcellus Shale in 2016; and

•	the sale of non-strategic US onshore assets in 2015.

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•	94 MMBoe in the DJ Basin;

•	74 MMBoe in the Delaware Basin;

•	6 MMBoe in the Eagle Ford Shale; and

•	551 MMBoe in the Leviathan field.

•	34 MMBoe in the DJ Basin;

•	17 MMBoe in the Delaware Basin;

•	60 MMBoe in the Eagle Ford Shale; and

•	11 MMBoe in the Marcellus Shale, prior to divestiture.

•	263 MMBoe in the DJ Basin;

•	181 MMBoe in the Delaware Basin; and

•	38 MMBoe in the Eagle Ford 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 – Supplemental Oil and Gas Information (Unaudited) for additional information regarding estimates of crude oil, NGL and natural gas 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)	For each respective year, reserves associated with the Delaware Basin or the Eagle Ford Shale did not comprise 15% or more of total reserves on a BOE basis.

(3)	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.

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

(1)	Undeveloped acreage includes an exploration lease totaling approximately 55,000 gross (19,000 net) acres which had expired in 2016. The lease was subsequently negotiated with the government of Equatorial Guinea in 2017 and was extended.

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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. Israel development wells include the Leviathan 3, 4, 5 and 7 development wells and the Tamar Southwest well.

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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 Energy, 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; and

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

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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 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, 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 Gulf of Mexico; and

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

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

•	Item 1A. Risk Factors; and

•	Risk and Insurance Program.

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•	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;

•	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 2018 or 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, including access to sources of capital, such as debt and equity, and/or ability to finance planned capital expenditures and operations;

•	failure of our partners to fund their share of development costs or obtain financing could result in delay or cancellation of future projects, thus limiting our growth and future cash flows;

•	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 which 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; and

•	reduction or suspension of dividends on our common stock.

•	declines in our stock price;

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

•	a reduction in the carrying value of goodwill.

•	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, thereby increasing supply;

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

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

•	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, as well as the availability of battery storage;

•	the long-term impact on the crude oil market of the use of natural gas and electricity as an alternative fuel for road transportation or the use of natural gas as fuel for electricity generation impacting the demand for electricity;

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

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•	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;

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

•	domestic and foreign governmental regulations and taxes.

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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;

•	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;

•	US and international monetary policies impacting foreign exchange or repatriation restrictions in countries in which we conduct business;

•	war, piracy, acts of terrorism or civil unrest; 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 or cancel exploration and/or development 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;

•	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; and/or

•	restrict our ability to compete with imported volumes of crude oil or natural gas.

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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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•	new municipal, state or federal 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 and Indian 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.

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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 global 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 rigs, 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 of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our crude oil, natural gas and NGL operations;

•	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; and

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

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

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

•	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 and Texas;

•	harsh weather and rough seas offshore certain international locations, which could limit exploration activities; and

•	other natural disasters.

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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 Revolving Credit Facility; and

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

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•	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.

•	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.

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•	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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(1)	Proceeds for 2017 relate to the Marcellus Shale upstream divestiture and proceeds received from other transactions. Proceeds for 2016 primarily relate to US onshore non-strategic asset divestiture activity and the sell-down of Tamar interest. See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger

(2)	Goodwill at December 31, 2017 related to the Clayton Williams Energy Acquisition. Our previous goodwill balance 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 - E&P;

•	Results of Operations - Midstream;

•	Results of Operations - Corporate;

•	Liquidity and Capital Resources; and

•	Critical Accounting Policies and Estimates.

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•	entered the liquids-rich Eagle Ford Shale and Delaware Basin through the Rosetta Merger;

•	expanded our Delaware Basin position through the Clayton Williams Energy Acquisition;

•	exited the Marcellus Shale upstream and are exiting the Marcellus Shale midstream, thereby accelerating monetization of assets not attracting capital;

•	established the Noble Midstream business, including an initial public offering of Noble Midstream Partners, and executed the first asset drop down transaction; and

•	accelerated DJ Basin value through numerous acreage exchanges and sales.

•	focused capital and resources on highest-margin assets within US onshore liquids plays and the Eastern Mediterranean;

•	sanctioned the initial phase of Leviathan development, with first natural gas sales targeted for the end of 2019;

•	excluding the impact of the Marcellus Shale upstream divestiture, increased proved reserves by more than 65% from 2016;

•	excluding the impact of the Marcellus Shale upstream divestiture, increased total US onshore sales volumes by more than 15% from 2016 and shifted to an oilier production mix, with more than 40% of our US onshore consolidated sales volumes attributable to crude oil; and

•	improved well level and corporate returns with technology advancements and structural cost savings.

•	proactive and strategic action to manage within cash flows;

•	made net repayments of debt totaling $1.69 billion, since beginning of 2016 through cash on hand, proceeds from asset sales, and cash generated by our midstream business;

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

•	maintained our investment grade credit ratings.

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•	Execution of a disciplined capital allocation process by:

◦	designing a flexible investment program aligned with the current commodity price environment; and

◦	maintaining a strong balance sheet and liquidity position.

•	Enhancing capital efficiencies through:

◦	utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore finding and development costs; and

◦	driving Delaware Basin economics through development cycle efficiencies.

•	Leveraging the benefits of our well-positioned and diversified portfolio including:

◦	exercising investment optionality and flexibility afforded by our assets, which are largely held by production; and

◦	continuing portfolio optimization actions to maximize strategic value.

•	Capitalizing on a currently low-cost offshore environment with execution of high-quality, long-cycle development projects, such as:

◦	progressing Leviathan field development.

•	Maintaining financial strength through:

◦	focusing operational activities on high-margin, high-return assets;

◦	improving overall corporate returns; and

◦	ensuring cash flow sources and uses remain balanced.

•	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;

•	increased drilling activity, which may cause US onshore cost inflation pressure and result in certain current production becoming less profitable or uneconomic;

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

•	timing of the divestiture of the remaining 7.5% working interest in the Tamar and Dalit fields, in accordance with the Framework, which will leave us with a 25% working interest and will accelerate value realization, but lower our forward sales volumes;

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

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

•	additional purchases of producing properties or divestments of operating assets;

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

•	availability or reliability of supplier services, including access to support equipment and facilities, occurrence of pipeline disruptions, and/or potential pipeline and processing facility capacity constraints, which may cause delays, restrictions or interruptions in production and/or midstream processing;

•	timing and completion of midstream expansion projects by Noble Midstream Partners in areas that provide services to our assets;

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

•	impact of enhanced completion efforts for US onshore assets;

•	potential growth from participation in future, or decline from existing, non-operated wells;

•	abandonment of low-margin US onshore wells;

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

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

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

•	operating and development costs;

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

•	drilling results;

•	property acquisitions and divestitures;

•	exploration activity;

•	cash flows from operations, including cash flows from potential midstream drop-down transactions;

•	indebtedness levels;

•	availability of financing or other sources of funding;

•	impact of new laws and regulations on our business practices, including potential legislative or regulatory changes regarding the use of hydraulic fracturing; and

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

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Exploration Activities and Unproved Properties We may impair and/or relinquish certain undeveloped leases prior to expiration based upon changes in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors. In addition, in the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery or prospect is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense.

•	Development Concept Selection Costs We may write-off costs related to certain development concepts, including costs of related pre-FEED and FEED studies, associated with significant offshore projects, particularly those in remote or under-developed areas, when such development concepts are eliminated from further consideration based on the

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•	Producing Properties We may impair a proved property based on a decrease in forward commodity prices, or widening of basis differentials, or an increase in abandonment costs, among other factors.

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Divestments We may periodically divest certain assets to reposition our portfolio. When properties meet the criteria for reclassification as assets held for sale, they are valued at the lower of net book value or anticipated sales proceeds less transaction-related costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less transaction-related costs to sell. In addition, a further loss, which could be material, could occur upon closing of a sales transaction.

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•	total average daily sales volumes of 381 MBoe/d;

•	record average daily sales volumes for US onshore crude oil of 90 MBbl/d; and

•	average daily sales volumes for natural gas of 272 MMcf/d, net, in Israel, and an all-time record for full year average daily gross sales volumes for natural gas of 956 MMcfe/d, primarily from the Tamar field.

•	average realized crude oil price increase of 23% as compared to 2016;

•	average realized NGL price increase of 56% as compared to 2016;

•	average realized natural gas price increase of 24% as compared to 2016;

•	pre-tax loss of $1.8 billion, as compared with pre-tax loss of $1.3 billion for 2016; and

•	capital expenditures of $2.4 billion, excluding acquisitions, as compared with $1.2 billion for 2016.

(1)	See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions, Divestitures and Merger.

(2)	See Item 8. Financial Statements and Supplementary Data – Note 5. Asset Impairments.

(3)	See Item 8. Financial Statements and Supplementary Data – Note 3. Clayton Williams Energy Acquisition.

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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 is 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 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 Alba Plant in Equatorial Guinea.

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•	23% increase in average realized prices due to the partial rebalancing of global supply and demand factors;

•	higher US onshore sales volumes of 16 MBbl/d, including 5 MBbl/d contributed by recently acquired Clayton Williams Energy assets, primarily attributable to increased development and enhanced well design and completion techniques; and

•	higher sales volumes of 2 MBbl/d due to full year of production at Gunflint, a Gulf of Mexico project that started production in July 2016;

•	lower sales volumes of 14 MBbl/d primarily due to natural field decline in the Gulf of Mexico and Equatorial Guinea.

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

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

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

•	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 the Aseng and Alen fields, offshore Equatorial Guinea.

•	56% increase in average realized prices due to the partial rebalancing of global supply and demand factors; and

•	higher US onshore sales volumes of 7 MBbl/d, including 1 MBbl/d contributed by recently acquired Clayton Williams Energy assets, primarily attributable to increased development and enhanced well design and completion techniques;

•	lower sales volumes of 4 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.

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

•	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.

•	lower sales volumes of 312 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017; and

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•	lower sales volumes of 29 MMcf/d as a result of the sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016, partially offset by higher gross sales volumes from the field;

•	24% increase in average realized prices due to the partial rebalancing of global supply and demand factors; and

•	higher US onshore sales volumes of 40 MMcf/d, including 6 MMcf/d contributed by recently acquired Clayton Williams Energy assets.

•	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 Delaware 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.

•	net income from AMPCO and affiliates increased primarily due to higher realized methanol prices; and

•	net income from Alba Plant increased primarily due to higher LPG sales volumes and higher realized commodity prices.

•	net income from AMPCO and affiliates increased in 2016 as compared with 2015 primarily due to higher methanol sales volumes, partially offset by lower methanol prices; and

•	net income from Alba Plant remained relatively flat.

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(1)	United States upstream production expense includes charges from our midstream operations that are eliminated on a consolidated basis. See Item 1. Financial Statements – Note 15. Concentration of Risk.

(2)	Other International includes the North Sea in 2015.

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

•	increase of $82 million in US onshore, primarily in the DJ Basin, Delaware Basin and Eagle Ford Shale due to increased activity;

•	decrease of $19 million due to natural field decline in the Gulf of Mexico;

•	decrease of $17 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;

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

•	decrease of $11 million due to a 3.5% lower working interest in the Tamar field, offshore Israel, following the partial divestiture in December 2016.

•	decrease of $92 million in US onshore, 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 US onshore and Gulf of Mexico development activities; and

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

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•	decrease of $120 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;

•	increase of $57 million in the DJ Basin due to the shifting of crude oil volumes onto a new export pipeline and contractual increases of pipeline fees; and

•	increase of $47 million related to higher production in the Delaware Basin and Eagle Ford Shale.

•	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 new Gulf of Mexico projects at Big Bend and Dantzler (which began producing fourth quarter 2015) and Gunflint (which began producing in July 2016).

(1)	Eastern Mediterranean includes Israel and Cyprus.

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

(3)	Other International includes Newfoundland, Suriname and other new ventures.

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(4)	For a discussion of 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 and Undeveloped Leasehold Costs.

(5)	Includes lease rental and other exploration expense.

•	leasehold impairment expense related primarily to Gulf of Mexico unproved properties; and

•	dry hole cost of $7 million for the Araku-1 exploration well, offshore Suriname.

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

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

•	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; and

•	dry hole cost including the Cheetah well, offshore West Africa, and Other International dry hole cost.

(1)	DD&A expense includes accretion of discount on asset retirement obligations of $47 million in 2017, $48 million in 2016, and $43 million in 2015.

•	year-end reserve additions, primarily in US onshore due to enhanced well design and completion techniques in our horizontal drilling program and globally due to positive price revisions. For more information, see reserves discussion in Supplemental Oil and Gas Information (Unaudited);

•	slightly lower sales volumes in the DJ Basin and the impact of certain property divestitures since the second quarter 2016;

•	the Marcellus Shale upstream divestiture in second quarter 2017, which reduced 2017 DD&A expense by $291 million;

•	the sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016, which reduced 2017 DD&A expense by approximately $7 million;

•	a reduction in depletable costs of $153 million in the second quarter 2017 due to the reallocation of common asset costs from the Alen field, offshore Equatorial Guinea, to the West Africa natural gas monetization development project, which reduced 2017 DD&A expense by $37 million; and

•	lower sales volumes in the Gulf of Mexico due to natural field decline and reduction in the depletable costs due to downward revisions in estimates of asset retirement costs;

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•	higher US onshore sales volumes of 29 MBoe/d during 2017, including 7 MBoe/d contributed by recently acquired Clayton Williams Energy assets;

•	an increase in sales volumes from the Gunflint development, Gulf of Mexico, which commenced production in July 2016; and

•	higher gross sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.

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

•	increase of $134 million related to the acquisition of Eagle Ford Shale and Delaware Basin production in 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, the Aseng and Alen fields, to a lower DD&A rate asset, the Alba field.

•	progressed the construction and development of multiple major projects in the DJ and Delaware Basins;

•	began providing crude oil and produced water gathering services to an unaffiliated third party;

•	entered into the Advantage Joint Venture; and

•	entered into the Black Diamond Gathering arrangement with definitive agreements to acquire the Saddle Butte system.

•	pre-tax income of $233 million, as compared with pre-tax income of $176 million for 2016; and

•	capital expenditures, excluding acquisitions, of $399 million compared with capital expenditures of $42 million for 2016.

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•	an increase of $20 million in water services expense due to increased services provided by third parties as well as higher throughput volumes associated with fresh water services; and

•	an increase of $6 million in gathering and facilities operating expense due to higher gathered volumes, as well as due to new systems placed in service and expansion of the gathering infrastructure in 2017.

•	an increase of $12 million in water services expense due to an expanded scope of water services delivered; and

•	an increase of $7 million in gathering systems and facilities operating expense associated with higher gathered volumes as well as general repairs and maintenance of our gathering systems and facilities.

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

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

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(1)	Total cash at December 31, 2017 includes $18 million cash of Noble Midstream Partners and $37.5 million restricted cash related to the Saddle Butte acquisition that closed in first quarter of 2018. Total cash at December 31, 2016 includes $57 million cash of Noble Midstream Partners, and restricted cash of $30 million related to the Delaware Basin property acquisition that closed in January 2017.

(2)

In 2017, amount available to be borrowed under the Revolving Credit Facility excludes $265 million and $625 million available to be borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility (defined below), respectively, which are not available to Noble Energy for general corporate purposes. In 2016, it excludes $350 million available to be borrowed under the Noble Midstream Services Revolving Credit Facility. See discussion 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. Significant changes in our financial position impacting the ratio included $255 million net decrease in debt, $1.9 billion increase in shareholders' equity due to issuance of stock as part of consideration paid for Clayton Williams Energy Acquisition, $312 million increase due to issuance of Noble Midstream Partners Common Units and $100 million increase due to stock based compensation, offset by $190 million decrease in shareholders' equity from dividends paid and $1.1 billion decrease in shareholders' equity from current year net loss.

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•	$1.0 billion from the Marcellus Shale upstream divestiture;

•	$568 million on the sale of Greeley Crescent and Bronco acreage in the DJ Basin; and

•	$335 million from the sale of mineral and royalty assets.

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(1)	2017 costs include $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin asset acquisition.

(2)	2017 costs include $722 million of proved properties and $63 million of asset retirement obligations acquired in the Clayton Williams Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.

(3)	2017 includes gathering and processing assets of $48 million related to the Clayton Williams Energy Acquisition.

(4)	2017 includes our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.

(5)	Relates to US onshore assets.

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(1)	References are to the Notes accompanying Item 8. Financial Statements and Supplementary Data.

(2)	Long-term debt excludes capital lease obligations and includes our fixed rate debt and revolving credit facilities balances based on the maturity dates of the facilities.

(3)	Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2017.

(4)	Annual capital lease payments, net to our interest, exclude regular maintenance and operational costs.

(5)	Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to procure drilling rigs and other related equipment for exploratory and development drilling activities. See Counterparty Credit Risk, above.

(6)	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.

(7)	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 and Firm Transportation Commitments.

(8)	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.

(9)	The table excludes deferred compensation liabilities of $197 million as specific payment dates are unknown.

(10)	Asset retirement obligations are discounted.

(11)	Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2017.

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•

Acquisition costs - Costs associated with the purchase, lease or other costs to acquire mineral interests in crude oil and natural gas properties are initially capitalized as unproved property acquisition costs. These costs are commonly attributable to undeveloped leasehold costs or are derived from allocated fair values as a result of business combinations. Continued capitalization of these costs is dependent upon discovery of proved reserves. For example:

◦

If no proved reserves are discovered after exploration, drilling or lapse of the lease, then costs are impaired. As part of our periodic impairment review, we review undeveloped leasehold costs for potential impairment and if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we will record impairment expense related to the respective lease.

◦

If proved reserves are discovered, the related acquisition costs are reclassified to proved properties. We assess proved crude oil and natural gas properties and other investments for possible impairment whenever events or circumstances indicate that the recorded carrying values of the assets may not be recoverable. We recognize an impairment loss as a result of an event that causes us to consider the possibility that impairment may have occurred and when the estimated undiscounted future net cash flows from a property or other investment are less than the carrying value.

•

Exploratory well costs - Costs associated with drilling an exploratory well may be capitalized temporarily, or “suspended,” pending a determination of whether crude oil or natural gas have been discovered and can be estimated with reasonable certainty to be economically producible. We carry the costs of an exploratory well as an asset if we have found a sufficient quantity of reserves to justify its completion as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive Gulf of Mexico or international projects, it may take several years to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as

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•	Development well costs - Costs associated with drilling a development well to obtain access to and to produce proved reserves are capitalized. Development well costs are included in our periodic proved property impairment test noted above.

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Income Approach Under the income approach, the fair value of the Texas reporting unit is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors, including estimates of forecasted revenue and operating costs and proved reserves, as well as the success of future exploration for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods. Key assumptions used in the discounted cash flow model described above include estimated quantities of crude oil, natural gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer group based weighted average cost of capital.

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Market Approach Under the market approach, we estimate the fair value of the Texas reporting unit by comparison to similar businesses whose securities are actively traded in the public market The market approach requires management to make certain judgments about the selection of comparable companies and/or comparable recent company and asset transactions and transaction premiums, thereby creating a group of guideline public companies or transactions, or a peer group, that are engaged in similar operations with comparable risks and returns as our reporting unit.

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•	the status of negotiations with counterparties regarding partial or permanent release of our contract commitments;

•	the status of FERC approval of prospective pipeline projects;

•	the timing of commercial availability of approved pipelines upon completion of construction; and

•	the likelihood of capacity utilization through purchase of third party gas, which would reduce unutilized volume commitments.

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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 gathering and processing expenses were historically presented as components of other operating expense, net, in our consolidated statement of operations. Beginning in 2017, we changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportation and processing expense. For the years ended December 31, 2016 and 2015, these costs totaled $17 million and $17 million, respectively, and have been reclassified from other operating expense, net to conform to current presentation.

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

(3)	Expense relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 17. Commitments and Contingencies.

(4)	Amount includes costs for legal and advisory services and employee severance charges.

(5)	Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.

(6)	See Note 3. Clayton Williams Energy Acquisition.

(7)	Expenses are associated with corporate organizational activities.

(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 4. Acquisitions, Divestitures and Merger.

(10)	See Note 9. Asset Retirement Obligations.

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

(12)	See Note 4. Acquisitions, Divestitures and Merger.

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(1)	Proceeds relate to the farm-out of a 35% interest in Block 12 offshore Cyprus and were received in January 2017. See Note 4. Acquisitions, Divestitures and Merger.

(4)	Relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See Note 4. Acquisitions, Divestitures

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US Onshore Divestitures During 2017, we received total proceeds of $671 million resulting from the sale of certain US onshore properties, including $568 million related to divestment of non-core acreage in the DJ Basin. Proceeds were applied to reduce field basis with no recognition of gain or loss. A subsequent closing for certain non-core DJ Basin operated properties, in the amount of approximately $40 million, is expected to occur in mid-2018.

•	Sale of Mineral and Royalty Assets We received $335 million and recognized a gain of $334 million on the sale of mineral and royalty assets covering approximately 140,000 net mineral acres concentrated primarily in Texas, Oklahoma and North Dakota.

•

Delaware Basin Acquisition In January 2017, we completed the acquisition of Delaware Basin properties, including seven producing wells, thus increasing our contiguous acreage position in the Reeves County area. Consideration totaled $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost. Initial consideration of $30 million was paid into an escrow account in fourth quarter 2016 and reflected as a restricted asset in our consolidated balance sheet as of December 31, 2016.

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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, with the remainder of the sale closing in 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss;

•	sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern Montana, and certain other smaller US onshore 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, which included the Karish and Tanin fields, offshore Israel, 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 and Dalit fields, offshore Israel, in compliance with the terms of the Framework, which requires us to reduce our ownership interest in the fields 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 fields basis and resulted in the recognition of a $261 million gain; and

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•	received proceeds of $131 million related to the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery, offshore Cyprus. 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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•	50% interest in Advantage Pipeline, which owns and operates a 70-mile crude oil pipeline in Texas (See Note 4 – Acquisitions, Divestitures and Merger);

•	50% interest in CONE Gathering, which owns and operates natural gas gathering facilities servicing the Marcellus Shale (See Note 4 – Acquisitions, Divestitures and Merger);

•	34% interest in CONE Midstream, a public master limited partnership, which constructs, owns and operates natural gas gathering and other midstream energy assets in the Marcellus Shale;

•	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 (LPG) processing plant in Equatorial Guinea.

(1)	CONE Investments include CONE Midstream and CONE Gathering. The investments are included in assets held for sale at December 31, 2017.

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(1)	We have entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes covered by the basis swap contracts.

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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)	In fourth quarter 2017, we repaid $550 million of borrowings under the Term Loan Facility and $18 million of our outstanding Senior Notes due June 1, 2022.

(2)	In third quarter 2017, we redeemed all of our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August 15, 2047.

(3)	Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13%.

(4)	The reduction from 2016 includes $41 million related to other obligations for drilling commitments assumed by the acquirer of the Marcellus Shale upstream assets and $60 million of capital lease principal payments.

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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 London interbank offered rate (LIBOR) for an interest period of one month plus 1.00%; or

•	in the case of 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)	During 2017, we awarded approximately 1.9 million shares of restricted stock for the conversion of Clayton Williams Energy shares into Noble Energy shares as part of the Clayton Williams Energy Acquisition. All awards subsequently vested during 2017. These awards are included in the above table. See Note 3. Clayton Williams Energy Acquisition.

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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)	Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.

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(1)	Intersegment eliminations related to (loss) income before income taxes are the result of Midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation.

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(1)	The 2017 amount includes approximately 1.9 million shares of restricted stock awarded to former holders of Clayton Williams Energy outstanding stock awards as part of the Clayton Williams Energy Acquisition. See Note 3. Clayton Williams Energy Acquisition.

(2)	The 2017 amount includes approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of Clayton Williams Energy restricted shares and options pursuant to the purchase and sale agreement.

(3)	For the years ended December 31, 2017 and 2016, 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.

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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)

The 2015 US revisions were primarily associated with negative price revisions of 70 MMBbls to our onshore programs due to a decline in the 12-month average price of crude oil; partially offset by positive revisions of 14 MMBbls due to producing well performance and optimized lateral lengths in the Delaware Basin and Eagle Ford Shale. Equatorial Guinea revisions were associated with negative price revisions.

(2)	The 2015 increase in US reserves was attributable to DJ Basin development.

(3)	The 2015 increase was attributable to reserves acquired in the Rosetta Merger.

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(4)	In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets.

(5)	Equatorial Guinea production included sales from Alba Plant of approximately 1 MMBbl in 2017 and 3 MMBbl in each of the years 2016 and 2015.

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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; partially offset by a positive revision from our Marcellus Shale program due to positive well performance.

(2)	The 2015 additions included 14 MMBbls due to positive producing well performance and optimized lateral lengths in the DJ Basin.

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(1)

In accordance with the terms of the Framework, we are required to reduce our ownership in the Tamar and Dalit fields from 36% to 25% by year-end 2021. During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. At December 31, 2017, an additional 7.5% interest is included in assets held for sale. Proved reserves associated with the interest currently held for sale total approximately 502 Bcf, including 89 Bcf of PUDs, at December 31, 2017 and are included in the table above. In January 2018, we entered into an agreement to divest the 7.5% interest. See Note 4. Acquisitions, Divestitures and Merger.

(2)

The 2015 US revisions were primarily associated with negative price revisions of 1.1 Tcf to our onshore programs due to a decline in the 12-month average price, offset by a positive revision primarily to our Marcellus Shale program due to positive well performance. Equatorial Guinea revisions were associated with positive performance revisions to the Alba field. Israel revisions were primarily associated with negative performance revisions in the Mari-B field.

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(3)	The 2015 increase in US reserves included an increase of 176 Bcf in the DJ Basin and 81 Bcf from Marcellus Shale development due to positive producing well performance and optimized lateral lengths.

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

(5)	In 2016, we sold US onshore assets in the DJ Basin and Eagle Ford Shale. We also executed an acreage exchange in the Marcellus Shale where we relinquished 185 Bcf, and we reduced our ownership in the Tamar field, offshore Israel.

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(1)	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.

(2)	See Note 4. Acquisitions, Divestitures and Merger.

(3)	2017 asset impairments relate primarily to the Gulf of Mexico Troubadour well.

(4)

Income tax expense is based upon respective corporate statutory tax rates. During 2017, 2016, and 2015, 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.

(5)	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.

(6)	Equatorial Guinea exploration expense includes amounts related to the write off of costs associated with certain discoveries. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

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(1)	Other International includes Newfoundland, Suriname, Falkland Islands, other new ventures and previous North Sea operations, which are in the process of being decommissioned.

(2)	2017 proved and unproved property acquisition costs include amounts allocated from the Clayton Williams Energy Acquisition (See Note 3. Clayton Williams Energy Acquisition) and the Delaware Basin Acquisition (See Note 4. Acquisitions, Divestitures and Merger).

(3)	2017 exploration costs include primarily capitalized interest on Gulf of Mexico projects, and $7 million dry hole cost related to the Araku-1 exploration well, offshore Suriname. The remainder relates to seismic expense and drilling costs.

(4)	Worldwide development costs include amounts spent to develop PUDs of approximately $1.2 billion in 2017, $656 million in 2016, and $1.5 billion in 2015.

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(1)	Unproved oil and gas property cost at December 31, 2017 include previous acquisition costs of $1.6 billion related to the Clayton Williams Energy Acquisition, and $1.1 billion and $149 million related to the Delaware Basin and Eagle Ford Shale properties.

(2)	Proved oil and gas properties at December 31, 2017 include asset retirement costs of $941 million and assets held for sale of $448 million.

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(1)

In accordance with the Framework, we are required to reduce our ownership in the Tamar and Dalit fields from 36% to 25% by year-end 2021. During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. Therefore, amounts at December 31, 2017 and 2016 reflect a 32.5% working interest, while 2015 amounts reflect a 36% working interest. At December 31, 2017, 7.5% of our 32.5% interest is included in assets held for sale. The portion of the standardized measure of discounted future net cash flows included in the table above, and associated with the interest currently held for sale, totals approximately $650 million at December 31, 2017. See Note 4. Acquisitions, Divestitures and Merger. The 2017 increase in the standardized measure of discounted future net cash inflows relates primarily to the sanction of the first phase of development of the Leviathan field.

(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. As of December 31, 2017, US future income tax expense includes the expected impact of the recent Tax Reform Legislation. As of December 31, 2017, 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)	The increase in 2017 and the decrease in 2015 were driven primarily by higher and lower, respectively, 12-month average commodity prices.

(2)	Purchase of minerals in 2017 relates to reserves acquired in the Clayton Williams Energy Acquisition.

(3)

The increase in 2017 future income tax expense relates primarily to the increase in profit and levy taxes in Israel, partially offset by the decrease in future corporate income tax rate in Israel. The increase in profits tax is driven by a significant increase in future cash flows related to the Leviathan project sanctioning in 2017. The increase in US tax expense due to the increase in future taxable income was offset by the decrease in tax expense associated with utilization of future net operating losses and decrease in applicable tax rate from 35% to 21% due to the changes in the US Tax Law effective January 1, 2018. 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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•	No unusual or infrequent activity.

•	$2.4 billion loss on Marcellus Shale upstream divestiture (See Note 4. Acquisitions, Divestitures and Merger).

•	$98 million loss on extinguishment of debt (See Note 10. Long-Term Debt).

•	$270 million deferred tax benefit, net, related to recent changes in federal income tax regulations; and

•	$334 million gain on sale of mineral and royalty assets (See Note 4. Acquisitions, Divestitures and Merger).

•	$80 million gain on extinguishment of debt.

•	$25 million purchase price allocation adjustment related to Rosetta Merger (See Note 4. Acquisitions, Divestitures and Merger).

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

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

•	$92 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 (loss) as each quarterly computation is based on the earnings (loss) for the individual quarter as reported with rounding applied.

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(a)	The following documents are filed as a part of this report:

(1)	Financial Statements: The consolidated financial statements and related notes, together with the reports of KPMG LLP, Independent Registered Public Accounting Firm, appear in Part II, Item 8, Financial Statements and Supplementary Data, of this Form 10-K.

(2)	Financial Statement Schedules: All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instruction or are inapplicable and, therefore, have been omitted.

(3)	Exhibits: The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as part of this Form 10-K.

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