Portions of the Registrant’s definitive proxy statement for the 2020 Annual Meeting of Shareholders to be held on April 28, 2020, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2019, are incorporated by reference into Part III.

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•	our growth strategies, including our capital spending plans;

•	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 liquids (NGLs) and natural gas resources;

•	anticipated trends in our business;

•	market conditions in the oil and gas industry;

•	the impact of governmental regulation, including United States (US) federal, state, local, and foreign host government tax regulations, fiscal policies and terms, as well as that involving the protection of the environment or marketing of production and other regulations;

•	our ability to make and integrate acquisitions or execute divestitures; and

•	access to resources.

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(1)

Million barrels oil equivalent. 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.

(1)	Includes negative price revisions of 53 MMBoe in 2019 and positive price revisions of 27 MMBoe and 30 MMBoe in 2018 and 2017, respectively.

(1)	In Israel, PUDs revisions of previous estimates reflects a reclassification to developed reserves associated with our Tamar field based upon our determination the reserves are accessible with limited further development. As such, we concurrently reflect an upward

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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, 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;

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•	NSAI is engaged by, and has direct access to, the Audit Committee.

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(1)	Average sales prices exclude gains or losses on commodity derivative instruments. See Item 8. Financial Statements and Supplementary Data – Note 14. Derivative Instruments and Hedging Activities.

(2)	Average production cost includes oil and gas production operating costs, workover and repair expense and excludes production and ad valorem taxes, gathering, transportation and processing expense, and other royalty expense.

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

(4)	Amounts include Gulf of Mexico assets prior to sale in second quarter 2018 and Marcellus Shale assets prior to sale in second quarter 2017. See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions and Divestitures.

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(1)	Approximately 80% relates to acreage on which we have not recorded PUDs. Of the remaining acreage, there are no PUDs on acreage we plan to let expire as our development plan contemplates the drilling or renewing of leases associated with this acreage prior to expiration.

(2)	Acreage relates to the Alon D license.

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(1)	Amounts include wells awaiting completion activities, with the exception of Tamar Southwest as it is not in the process of completing at December 31, 2019. Amounts exclude wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well.

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(1)	Amounts include net developed and net undeveloped acres. Total excludes approximately 181,000 net acres in the Powder River and Green River Basins and approximately 239,000 net acres in other US onshore locations.

(2)	The number of wells drilled refers to the number of wells completed, regardless of when drilling was initiated. Amount excludes two refracture wells in the Eagle Ford Shale.

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(1)	Includes 639 MMBoe, 281 MMBoe, and 22 MMBoe related to the Leviathan, Tamar, and Tamar Southwest fields, respectively.

(2)	The number of wells drilled refers to the number of wells completed, regardless of when drilling was initiated.

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•	Advantage Pipeline L.L.C. (Advantage Pipeline), which owns a crude oil pipeline system in the southern Delaware Basin from Reeves County, Texas to Crane County, Texas (Advantage Pipeline System);

•	EPIC Y-Grade, which owns a Y-Grade pipeline from the Delaware Basin to Corpus Christi, Texas (EPIC Y-Grade Pipeline);

•	EPIC Crude Holdings, which is currently constructing a crude oil pipeline from the Delaware Basin to Corpus Christi, Texas (EPIC Crude Oil Pipeline); and

•	Delaware Crossing, which is currently constructing a crude oil pipeline and gathering system in the Delaware Basin.

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•	the Bureau of Land Management (BLM) published a final rule governing hydraulic fracturing on federal and Indian lands; the rule was repealed in 2017, but state and environmental groups have challenged the rollback;

•	the Occupational Safety and Health Administration (OSHA) has lowered exposure limits for workers who use silica (sand), which can include hydraulic fracturing activities, and silica work practices have become stricter; and

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state and federal regulatory agencies have focused on areas where there have been connections between hydraulic fracturing related activities, particularly the operation of injection wells used for oil and gas waste disposal or hydraulic fracturing activities, and seismic activity due to the presence of critically stressed faulting and orientation, which some have termed “induced seismicity”. Some state regulatory agencies have modified their regulations to account for such induced seismicity and operators, including us, have implemented practices to avoid, monitor, mitigate and respond as necessary to induced seismicity.

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•	reduction of our revenues, profit margins, operating income, and cash flows;

•	reduction in the amount of crude oil, NGLs and natural gas that we can produce economically, leading to shut-in or early abandonment of producing wells, including low-margin US onshore 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;

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

•	delay, reduction, or cancellation of future capital investment programs relating to our exploration and/or development projects, resulting in a reduced ability to develop or replace our reserves;

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

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

•	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, which 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 finance leases;

•	a series of credit rating downgrades or other negative rating actions, which could increase our future 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 and our ability to access the commercial paper market;

•	reduction or suspension of dividends or repurchases of our common stock;

•	declines in our stock price; and

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

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•	global demand for crude oil, NGLs, and natural gas, as impacted by economic factors that affect gross domestic product growth rates of countries around the world, including impacts from global health epidemics and concerns, such as the coronavirus;

•	global supply for crude oil, NGLs, and natural gas, including inventories, as impacted by OPEC and non-OPEC countries;

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

•	new technologies that promote fuel efficiency or fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and impact demand for crude oil as a transportation fuel and reduce energy consumption;

•	the price and availability of alternative fuels and battery storage and 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;

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

•	geopolitical conditions and events, including domestic political uncertainty or foreign generational leadership or regime changes, changes in government energy policies, including imposed price controls and/or product subsidies, the impact of trade embargoes or imposed tariffs, or instability/armed conflict in hydrocarbon-producing regions;

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

•	periods when production surpasses local pipeline/rail transportation and/or refining capacity, which in turn results in transportation constraints and significant discounts to our realized prices;

•	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; and

•	domestic and foreign governmental regulations and taxes.

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

•	operating and development costs;

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

•	drilling results;

•	cash flows from operations and 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;

•	property acquisitions and divestitures;

•	exploration activity; and

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

•	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

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•	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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renegotiation, modification or nullification of existing contracts, which 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 increase the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;

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

•	changes in drilling, environmental, social or safety regulations;

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

•	political conditions and events which may cause the potential for Israel natural gas production and regional exports to be interrupted;

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

•	US and international monetary policies impacting foreign exchange or repatriation restrictions in 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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•	increased volatility in global crude oil, NGL and natural gas 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, third-party providers or supplies to enter or exit the countries where we conduct 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 purchasers, leading to interruption of commodity deliveries, claims of force majeure, and/or termination of sales contracts, resulting in a reduction in our revenues;

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

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

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•	have a negative impact on our ability to compete for oil and gas resources;

•	result in a failure to reach the intended target or lead to a drilling incident during drilling activities;

•	result in loss of production, or accidental discharge should production infrastructure be impacted;

•	result in supply chain disruptions which could delay or halt a development project, effectively delaying the start of cash flows from the project;

•	prevent us from marketing our production through a third-party gathering or pipeline service provider, resulting in a loss of revenues;

•	cause operational disruption if communication networks or power grids are targeted resulting in loss of revenues;

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

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

•	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; and

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

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•	reduce our proved reserves;

•	reduce our ability to explore for new proved reserves;

•	increase exploratory and development well drilling costs, operating or other costs;

•	delay, or preclude, project development resulting in longer development cycle times;

•	disrupt or prohibit our ability to construct or operate midstream assets;

•	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.

•	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 future quantities of proved reserves 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;

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•	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.

•	pipeline ruptures and spills;

•	fires, explosions, blowouts and well cratering;

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•	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 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 truck or rail car or train derailments;

•	leakage or loss of access to hydrocarbons resulting from formations with abnormal pressures and basin subsidence;

•	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.

•	hurricanes, tropical storms, windstorms, flooding or “superstorms,” which could affect our operations in Texas;

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

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

•	severe droughts, which could result in new restrictions on water usage in the DJ Basin and Texas;

•	harsh weather and rough seas offshore 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) may 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; and

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

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•	estimating future production from an area is consistent with historical production from similar producing areas;

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

•	future development, operating and abandonment costs, as well as timing of such activities; and

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

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(1)	Shares repurchased during the period related to stock received by us from employees for the payment of withholding taxes due on shares of common stock issued under stock-based compensation plans.

(2)	During fourth quarter 2019, we did not repurchase any shares under the $750 million share repurchase program, authorized by the Board of Directors and announced in February 2018, which expires on December 31, 2020.

(1)	Anadarko Petroleum Corp. is excluded from all periods in the graph below due to its acquisition by Occidental Petroleum Corp. in 2019.

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(1)	See Item 8. Financial Statements and Supplementary Data – Note 10. Impairments.

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

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•	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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•	Execution of a disciplined capital allocation process by:

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

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

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

◦	continuing portfolio optimization actions to maximize strategic value.

•	Enhancing capital efficiencies by:

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

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

◦	continuing development offshore Israel and monetizing natural gas offshore West Africa.

•	Maintaining financial strength through:

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

◦	improving overall corporate returns.

•	Commitment to people and communities in which we operate by:

◦	being a safe and reliable operator;

◦	complying with applicable air quality rules and environmental regulations; and

◦	advancing ESG initiatives.

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•	increased total average consolidated sales volumes by 3% to 355 MBoe/d, net;

•	increased average daily sales volumes for US onshore crude oil by 10% to 120 MBbl/d, net;

•	reduced total production expense per BOE by 3% as compared to 2018;

•	exceeded 2 Tcf, gross, of natural gas produced from the Tamar field since commencement of operations;

•	commenced production from the Leviathan field in December 2019;

•	invested in the EMG Pipeline, through our affiliate, EMED Pipeline B.V., enabling future flow of natural gas production from offshore Israel to customers in Egypt;

•	reduced capital expenditures, excluding acquisitions, by $571 million as compared with 2018;

•	drilled the Aseng 6P well, offshore Equatorial Guinea, and commenced production in fourth quarter 2019; and

•	sanctioned the Alen Gas Monetization project, offshore Equatorial Guinea.

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

(2)	See Item 8. Financial Statements and Supplementary Data – Note 10. Impairments.

(1)	Natural gas from the Alba field is sold 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. See Items 1. and 2. Business and Properties – Delivery Commitments – West Africa Agreements.

(2)	Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investments and Other.

(3)	Includes 7 MBoe/d for 2018 related to Gulf of Mexico assets sold in second quarter 2018. See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions and Divestitures.

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(1)	Changes exclude impacts of commodity derivative instruments. See Item 8. Financial Statements and Supplementary Data – Note 14. Derivative Instruments and Hedging Activities.

•	9% decrease in average realized prices (see factors impacting global pricing at Executive Overview – Industry Outlook);

•	reduction in sales volumes of 5 MBbl/d due to the sale of our Gulf of Mexico assets in second quarter 2018; and

•	lower offshore West Africa sales volumes of 3 MBbl/d due to timing of liftings and natural field decline;

•	higher US onshore sales volumes of 11 MBbl/d primarily due to an increase in development activity in the DJ and Delaware Basins.

•	43% decrease in average realized prices (see factors impacting global pricing at Executive Overview – Industry Outlook); and

•	lower Eagle Ford Shale sales volumes of 6 MBbl/d due to reduced activity and natural field decline;

•	higher sales volumes of 12 MBbl/d in the DJ and Delaware Basins due to an increase in development activities.

•	13% decrease in average realized prices (see factors impacting global pricing at Executive Overview – Industry Outlook);

•	lower Eagle Ford Shale sales volumes of 41 MMcf/d due to reduced activity and natural field decline;

•	lower West Africa sales volumes of 28 MMcf/d due to natural field decline and planned maintenance at onshore facilities during first quarter 2019, which required shut-in for a portion of the period; and

•	lower Israel sales volumes of 14 MMcf/d primarily due to the sale of a 7.5% interest in the Tamar field in March 2018;

•	higher sales volumes of 91 MMcf/d in the DJ and Delaware Basins due to an increase in development activity.

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•	decrease in net income from AMPCO and affiliates primarily due to lower realized methanol prices; and

•	decrease in net income from Alba Plant primarily due to lower realized LPG prices.

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

(2)	US production expense includes charges from our midstream operations that are eliminated on a consolidated basis. See Item 8. Financial Statements and Supplementary Data – Note 3. Segment Information.

•	decrease in US lease operating expense primarily due to the sale of our Gulf of Mexico assets and cost reduction efforts, notably workover reductions and compression optimization, in the US onshore basins; and

•	decrease in other royalty expense due to lower commodity prices;

•	decrease in West Africa lease operating expense due to cost reduction efforts across all assets; and

•	decrease in production and ad valorem taxes due to production tax refunds;

•	increase in US gathering, transportation and processing (GTP) expense primarily due to increased development activity in the DJ Basin and higher-cost Delaware Basin; and

•	increase in Eastern Mediterranean lease operating expense due to planned maintenance activities.

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(1)	DD&A expense includes accretion of discount on asset retirement obligations (AROs) of $43 million in 2019 and $33 million in 2018.

(2)	Consolidated rates exclude sales volumes and expenses attributable to equity method investments.

•	capital investment and development activities in the DJ and Delaware Basins resulting in higher sales volumes; and

•	increase in Eastern Mediterranean primarily due to the retirement of certain capital assets resulting in accelerated depreciation;

•	decrease resulting from the sale of our Gulf of Mexico assets in second quarter 2018; and

•	reduced sales volumes in West Africa, as noted above, from natural field decline.

•	net cash receipt of $32 million; and

•	net non-cash decrease of $175 million in the fair value of our net commodity derivative liability, primarily driven by increases in the forward commodity price curve for crude oil.

•	net cash payment of $161 million; and

•	net non-cash increase of $224 million in the fair value of our net commodity derivative asset, primarily driven by decreases in the forward commodity price curve for crude oil.

•	sold substantially all of our US onshore midstream interests and assets and our incentive distribution rights to Noble Midstream Partners for total consideration of $1.6 billion;

•	expanded our long-haul business by developing strategic relationships in the Delaware Basin, exercising investment options in EPIC Y-Grade and EPIC Crude Holdings, and forming the Delaware Crossing crude oil pipeline joint venture, with total equity contributions of approximately $590 million; and

•	secured long-term takeaway at a lower cost in the DJ Basin through a strategic relationship with Saddlehorn.

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(1)	Relates to third-party mitigation activities we engage in to utilize a portion of our Marcellus Shale transportation commitments. Cost of purchased gas includes utilized and unutilized transportation expense.

(2)	Includes exit costs related to future commitments to a third-party resulting from a permanent capacity assignment.

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

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

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•	initiated a commercial paper program;

•	issued and redeemed notes, lowering interest expense and extending debt maturities;

•	established a new Noble Midstream Partners term loan;

•	increased the Noble Midstream Services Revolving Credit Facility capacity to almost $1.2 billion;

•	secured a $200 million preferred equity commitment at Noble Midstream Partners; and

•	completed our midstream asset sale and simplification to Noble Midstream Partners.

(1)	Total cash includes $3 million of restricted cash at December 31, 2018.

(2)	Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy for general corporate purposes.

(3)	Total debt excludes unamortized debt discount/premium and debt issuance costs. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt

(4)	We define our ratio of debt-to-book capital as total debt divided by the sum of total debt plus Noble Energy's share of equity.

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(1)	Amounts relate to US onshore undeveloped leasehold activity.

(2)	Amounts include capitalized interest that will be amortized into earnings over the useful life of the related assets.

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

(2)	Long-term debt excludes unamortized discounts, premiums, debt issuance costs and finance lease obligations.

(3)	Interest payments and commitment fees are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2019.

(4)	Annual lease payments exclude regular maintenance and operational costs.

(5)	Amount includes firm transportation exit cost accruals resulting from certain permanent capacity assignments.

(6)	Purchase and service obligations represent contractual agreements to purchase goods or services that are enforceable, 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.

(7)	The table excludes deferred compensation liabilities of $133 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data – Note 16. Stock-Based and Other Compensation Plans.

(8)	AROs are discounted.

(9)	Amount represents commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2019.

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Nature of Operations   Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns, operates and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins.

Note 1. Summary of Significant Accounting Policies

Basis of Presentation and Consolidation   We use accounting policies that conform to US GAAP. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated upon consolidation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Certain prior-period amounts have been reclassified to conform to the current period presentation.

Segment Information   Accounting policies are consistent across geographical segments. Transfers between segments are accounted for at market value. See Note 3. Segment Information.

Noble Midstream Partners Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (Noble Midstream Partners, Nasdaq: NBLX) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a variable interest entity (VIE). Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners.

Noncontrolling Interests Our consolidated financial statements include both noncontrolling interests and a redeemable noncontrolling interest. The noncontrolling interests represent the public's ownership in Noble Midstream Partners and third-party ownership in Noble Midstream Partners' consolidated non-wholly owned subsidiaries.

The redeemable noncontrolling interest represents third-party preferred equity secured by Noble Midstream Partners in March 2019. The entire equity commitment totals $200 million, of which $100 million was funded and the remaining $100 million is available for a one year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. The preferred equity partner can request redemption at a pre-determined base return following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the completion date of the EPIC Crude Oil Pipeline (defined below). As the preferred equity partner’s redemption right is outside of Noble Midstream Partners’ control, the preferred equity is not considered to be a component of shareholders' equity and, therefore, is reported as mezzanine equity. In addition, because the preferred equity is held by a third-party, it is considered a redeemable noncontrolling interest. We accrete changes in the preferred equity redemption value from the issuance date to the earliest redemption date and offset the accretion against additional paid in capital. See Note 4. Acquisitions and Divestitures.

Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. For certain entities, we serve as the operator and exert significant influence over the day-to-day operations. For other entities, we do not serve as the operator; however, our voting position on management committees or the board of directors allows us to exert significant influence over decisions regarding capital investments, budgets, turnarounds, maintenance, monetization decisions and other project matters. We consider these equity method investments essential components of our business as well as necessary and integral elements of our value chain in support of ongoing upstream operations. In order to reflect the economics associated with our integrated upstream value chain, we include income from equity method investments as a component of revenues in our consolidated statements of operations. See Note 5. Equity Method Investments.  

Use of Estimates   The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Estimated quantities of crude oil, NGL and natural gas reserves are the most significant of our estimates. See Supplemental Oil and Gas Information (Unaudited). Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, equity method investments, goodwill, intangible assets, exit cost liabilities and AROs, valuation

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allowances for receivables and deferred income tax assets, valuation of derivative instruments, and fair values, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Declines in commodity prices, or other events, could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties, or other long-lived assets, are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates.

Fair Value Measurements   Certain assets and liabilities are measured at fair value on a recurring basis on our consolidated balance sheets. Other assets and liabilities are measured at fair value on a nonrecurring basis. Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows:

•	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.

The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements.  We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature or maturity of the instruments.

Cash and Cash Equivalents  For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase.

Accounts Receivable and Allowance for Expected Credit Losses  Our accounts receivable result primarily from sales of crude oil, NGL and natural gas production and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. The majority of these receivables have payment terms of 30 days or less. Our accounts receivable reflects broad national and international customer base, which limits our exposure to concentrations of credit risk. We continually monitor the creditworthiness of the counterparties and have obtained credit enhancements from some parties in the form of parental guarantees or letters of credit.

At the end of each reporting period, we assess the recoverability of all material receivables using historical data, current market conditions, and reasonable and supportable forecasts of future economic conditions to determine their expected collectibility. The loss given default method is used when, based on management's judgment, an allowance for expected credit losses should be accrued on a material receivable to reflect the net amount expected to be collected. See “Recently Adopted Accounting Standards” below for discussion on our early adoption of Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses. See Note 2. Additional Financial Statement Information.

Property, Plant and Equipment   Significant accounting policies for our property, plant and equipment are as follows:

Oil and Gas Properties (Successful Efforts Method of Accounting)   We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are depleted using the unit-of-production method based on proved crude oil, NGL and natural gas reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A is eliminated and we either adjust the basis of the respective asset or recognize a gain or loss. Costs related to repair and maintenance activities are expensed as incurred.

Proved Property Impairment   For our proved properties, we routinely assess whether impairment indicators exist and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. We conduct an impairment test in the event impairment indicators exist. Under such test, we estimate future net cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. Other long-lived assets, such as our midstream assets, are evaluated in a manner consistent with our policy for proved property.

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When the carrying amount of the proved property exceeds its estimated undiscounted future net cash flows, an impairment is indicated and the fair value of the asset is then estimated. Fair value inputs, which are level 3 on the fair value hierarchy, may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future net cash flows are based on management’s expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. In the event of an impairment, the carrying amount of the proved property is reduced to estimated fair value. See Note 10. Impairments.

Unproved Property   Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves resulting from acquisitions. Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves.

We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment. In determining whether a significant unproved property is impaired, we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property.

When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future net cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, NGL and natural gas reserves, future commodity prices and future costs to produce the reserves. Reserves volumes are reduced by risk adjustments applied to probable and possible reserves. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

Properties Acquired in Business Combinations   When sufficient market data is not available, we determine the fair values of proved and unproved oil and gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, NGL and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values.

Assets Held for Sale At the end of each reporting period, we evaluate properties being marketed for sale to determine whether any should be reclassified as held for sale. If the held-for-sale criteria are met, the property is reclassified as held for sale on our consolidated balance sheets and valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense is recorded for any excess of net book value over anticipated sales proceeds less costs to sell.

Exploration Costs   Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization 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 international projects, it may take us more than one year 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 we are actively pursuing access to necessary facilities, permits and approvals and we believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

Property, Plant and Equipment, Other   Other property includes automobiles, trucks, an airplane, office furniture, computer equipment, buildings, leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, ranging from three to thirty years. Other property also includes linefill, which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment.

Capitalization of Interest   We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average interest rate we pay on long-term debt, including our unsecured revolving credit facilities, term loan credit facilities and Senior

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Notes. Capitalized interest is included in the cost of oil and gas assets and is amortized with other costs on a unit-of-production basis.

Asset Retirement Obligations   Asset retirement obligations (AROs) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which we have an existing legal obligation associated with the retirement that can reasonably be estimated. The associated asset retirement cost is capitalized as part of the carrying value of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by the expected future cash outflows required to satisfy the obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense included in DD&A expense in the consolidated statements of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset. See Note 7. Asset Retirement Obligations.

Intangible Assets Intangible assets consist of customer contracts and relationships that were recorded at their estimated fair values at the date of acquisition. Amortization is calculated using the straight-line method, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible assets, which is currently over periods of seven to 13 years. As of December 31, 2019, the net book value of our intangible assets was $278 million, net of accumulated amortization of $62 million. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. See Note 4. Acquisitions and Divestitures.

Exit Costs   We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions. Fair value estimates are based on expected future discounted cash outflows required to satisfy the obligation, net of estimated recoveries. In periods subsequent to initial measurement, changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, are recognized as an adjustment to the liability in the period of the change. Exit costs, and associated accretion expense, are included in other operating expense, net in our consolidated statements of operations. See Note 11. Exit Cost – Transportation Commitments.

Derivative Instruments and Hedging Activities   All derivative instruments are recorded on our consolidated balance sheets as either an asset or liability and are measured at fair value. We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur.

We offset the fair value amounts recognized for derivative instruments against the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master agreement with netting clauses. See Note 14. Derivative Instruments and Hedging Activities.

Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded on grant-date at fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. See Note 16. Stock-Based and Other Compensation Plans.

Contingencies   We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 12. Commitments and Contingencies.

Income Taxes We are subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return.

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.

In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, current financial position, results of operations, projected future taxable income and tax planning strategies as well as current and forecasted business economics in the oil and gas industry. The

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amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. See Note 13. Income Taxes.

Treasury Stock   We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets.

Revenue Recognition Our revenues are derived primarily from the sale of crude oil, NGL and natural gas production to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We recognize revenues based on the amount of product sold to a customer when control transfers to the customer. Our revenue arrangements include the following:

Crude Oil Sale Arrangements – US We sell our share of crude oil production under both short-term and long-term contracts at market-based prices, adjusted for location, quality and transportation charges. Revenue is measured based on the index-based contract price, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

Crude Oil Sale Arrangements – West Africa We sell our share of crude oil and condensate at market-based prices and recognize revenue at the time a crude oil cargo is loaded onto the tanker.

Natural Gas and NGLs Sale Arrangements – US We evaluate these arrangements to determine whether the processor is a service provider or a customer. In arrangements where we determine that the processor is a customer, we record revenue when the processor takes control of the natural gas and NGLs and in the amount of proceeds expected to be received, net of any fees or deductions charged by the processor. In other arrangements, we receive natural gas and NGL products “in-kind” after processing at the tailgate of the plant. In these arrangements, where we determine that the processor is a service provider, we record revenue and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer.

Natural Gas Sale Arrangements – West Africa We sell our share of natural gas production under a long-term contract for $0.25 per MMBtu to a methanol plant, a liquefied petroleum gas (LPG) plant, a liquefied natural gas (LNG) plant and a power generation plant. We recognize revenue upon transfer of control of product to these processors.

Natural Gas Sale Arrangements – Eastern Mediterranean We sell our share of natural gas production primarily based on long-term contracts with fixed volume commitments. Performance obligations are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of these sales contracts contain take-or-pay provisions whereby the customers are required to purchase a contractual minimum over varying time periods. We record revenues related to the volumes delivered at the contract price at the time of delivery.

The following table provides estimated future revenues for remaining performance obligations under fixed volume natural gas sales agreements using the contractual fixed base or floor price provision in effect. Actual future sales volumes under these agreements may exceed future minimum volume commitments. In addition, future sales revenues will vary due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes. Certain of these contracts contain embedded derivatives for which we have elected the normal purchases and normal sales scope exception, which excludes the derivatives from mark-to-market accounting.

Estimated future revenues related to remaining performance obligations were as follows as of December 31, 2019:

(millions)	2020			2021			2022			2023			2024			Thereafter			Total
Natural Gas Revenues(1)	$	743		$	768		$	583		$	583		$	583		$	5,259		$	8,519

(1)	Includes amounts related to the Tamar and Leviathan fields, offshore Israel.

Oil and Gas Purchase and Sale Arrangements We enter into separate third-party purchase and sale transactions at prevailing market prices to mitigate unutilized pipeline transportation commitments. We recognize associated revenues and expenses on a gross basis, as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. We also enter into crude oil buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. We account for these transactions on a net basis and record the residual transportation fee within gathering, transportation and processing expense in the consolidated statements of operations.

Midstream Services Arrangements Third-party Midstream services revenues relate to fixed fee arrangements for gathering, transportation and storage services. Our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress.

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Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy  Basic earnings (loss) per share (EPS) of our common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss. In the event of a net loss, we exclude the effect of outstanding common stock equivalents from the calculation of diluted EPS as the inclusion would be anti-dilutive.

Recently Adopted Accounting Standards

Leases Effective January 1, 2019, we adopted Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a right-of-use (ROU) asset and lease liability on the balance sheet for the rights and obligations created by leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained.

Upon adoption, we elected the following optional practical expedients:

•	transition “practical expedients,” permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs;

•	the practical expedient pertaining to land easements, allowing us to account for existing land easements under our previous accounting policy; and

•	the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class).

We adopted ASC 842 using the modified retrospective method and recorded ROU assets and lease liabilities of $282 million and $287 million, respectively, primarily related to operating leases. ROU assets and corresponding liabilities are based on the present value of the minimum lease payments. Our accounting for finance leases remains substantially unchanged. Adoption of ASC 842 did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows.

Additional information related to our accounting policies for leases is as follows:

•	Most of our leases do not provide implicit borrowing rates; therefore, using the portfolio approach, we determine the present value of lease payments using hypothetical secured borrowing rates based on information available at lease commencement.

•

Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.

•	Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Variable payments related to lease agreements are not material.

•

We have lease agreements that include lease and non-lease components, such as equipment maintenance, that are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as office space, lease and non-lease components are accounted for separately. While some lease agreements include residual value guarantees, there are no material guarantees that impact our lease payments.

•	ROU assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable.

See Note 9. Leases.

Financial Instruments: Credit Losses In June 2016, the FASB issued ASU 2016-13, which replaces the incurred loss impairment methodology with an expected credit loss methodology for financial instruments, including financial assets measured at amortized cost, such as trade and joint interest billing receivables, and off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We early adopted this ASU in fourth quarter 2019. This adoption did not have a material impact on our financial statements.

Income Taxes In December 2019, the FASB released Accounting Standards Update No. 2019-12 (ASU 2019-12): Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds

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guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. We early adopted this ASU in fourth quarter 2019. This adoption did not have a material impact on our financial statements.

Recently Issued Accounting Standards

None that are expected to have a material impact on our financial statements.

Note 2. Additional Financial Statement Information

Statements of Operations Information Other statements of operations information is as follows:

	Year Ended December 31,
(millions)	2019				2018				2017
Other Revenue
Income from Equity Method Investments and Other	$	51			$	172			$	177
Midstream Services Revenues - Third Party	94				78				19
Total	$	145			$	250			$	196
Production Expense
Lease Operating Expense	$	532			$	576			$	571
Production and Ad Valorem Taxes	175				190				118
Gathering, Transportation and Processing Expense	417				393				432
Other Royalty Expense	13				38				20
Total	$	1,137			$	1,197			$	1,141
Exploration Expense
Leasehold Impairment and Amortization	$	—			$	1			$	62
Dry Hole Cost (1)	100				1				9
Seismic, Geological and Geophysical	21				22				27
Staff Expense	48				54				55
Other	33				51				35
Total	$	202			$	129			$	188
Loss on Marcellus Shale Upstream Divestiture and Other
Loss on Sale	$	—			$	—			$	2,270
Exit Cost	—				—				93
Other	—				—				16
Total	$	—			$	—			$	2,379
Other Operating Expense, Net
Marketing Expense	$	34			$	40			$	47
Firm Transportation Exit Cost (2)	88				—				—
Clayton Williams Energy Acquisition Expenses	—				—				100
Loss (Gain) on Asset Retirement Obligation Revisions	9				(25		)		(42		)
Other, Net	83				35				33
Total	$	214			$	50			$	138

 

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

(2)	See Note 11. Exit Cost – Transportation Commitments.

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Balance Sheet Information Other balance sheet information is as follows:

	December 31,
(millions)	2019				2018
Accounts Receivable, Net
Commodity Sales	$	446			$	383
Joint Interest Billings	164				137
Other	128				111
Allowance	(8		)		(15		)
Total	$	730			$	616
Other Current Assets
Commodity Derivative Assets	$	14			$	180
Inventories, Materials and Supplies	59				55
Assets Held for Sale (1)	14				133
Prepaid Expenses and Other Current Assets	61				50
Total	$	148			$	418
Other Noncurrent Assets
Equity Method Investments (2)	$	1,066			$	286
Operating Lease Right-of-Use Assets (3)	227				—
Customer-Related Intangible Assets, Net	278				310
Goodwill	110				110
Mutual Fund Investments	27				38
Other Noncurrent Assets	126				97
Total	$	1,834			$	841
Other Current Liabilities
Production and Ad Valorem Taxes	$	118			$	103
Asset Retirement Obligations	84				118
Interest Payable	74				66
Operating Lease Liabilities (3)	88				—
Compensation and Benefits Payable	126				83
Other Current Liabilities	229				149
Total	$	719			$	519
Other Noncurrent Liabilities
Deferred Compensation Liabilities	$	133			$	147
Asset Retirement Obligations	730				762
Operating Lease Liabilities (3)	164				—
Firm Transportation Exit Cost Accrual (4)	129				67
Other Noncurrent Liabilities	222				189
Total	$	1,378			$	1,165

(1)	Amounts relate to divestitures of non-core assets and acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures.

(2)	See Note 5. Equity Method Investments.

(3)	Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption. See Note 9. Leases.

(4)	See Note 11. Exit Cost – Transportation Commitments.

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Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash:

		December 31,
(millions)		2019				2018
Cash and Cash Equivalents at Beginning of Period		$	716			$	675
Restricted Cash at Beginning of Period		3				38
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period		$	719			$	713
Cash and Cash Equivalents at End of Period		$	484			$	716
Restricted Cash at End of Period		—				3
Cash, Cash Equivalents, and Restricted Cash at End of Period		$	484			$	719

A significant portion of our cash is located in foreign subsidiaries. The cash is denominated in US dollars and at certain times is invested in highly liquid money market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts.

Supplemental Cash Flow Information Supplemental statements of cash flow information is as follows:

	Year Ended December 31,
(millions)	2019				2018				2017
Cash Paid During the Year For
Interest, Net of Amount Capitalized (1)	$	208			$	270			$	346
Income Taxes Paid, Net	76				172				121

(1)	Interest capitalized totaled $102 million in 2019, $73 million in 2018 and $49 million in 2017.

See Note 9. Leases for supplemental cash flow information related to leases.

Significant Purchasers Non-affiliated purchasers who accounted for 10% or more of our commodity sales were as follows:

	Year Ended December 31,
	2019			2018			2017
Percentage of Crude Oil Sales
Shell (1)	22	%		22	%		22	%
BP (2)	18	%		31	%		15	%
Percentage of Total Crude Oil, NGL & Natural Gas Sales
Shell (1)	15	%		14	%		13	%
BP (2)	14	%		17	%		10	%

(1)	Includes sales to Shell Energy North America and Shell Trading (US) Company (collectively, Shell).

(2)	Includes sales to BP America Production, BP Energy Co and BP Products North America, Inc (collectively, BP).

Note 3. Segment Information

We have the following reportable segments: United States (US onshore (Marcellus Shale until July 2017) and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Suriname (until November 2018), Falkland Islands (until December 2018), Canada, Colombia and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners.

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The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other financially attractive midstream projects, with current focus areas being the DJ and Delaware Basins. The chief operating decision maker analyzes income (loss) before income taxes to assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing the Company's operating and financial performance across periods.

Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements, are recorded at the corporate level.

					Oil and Gas Exploration and Production																Midstream
(millions)	Consolidated				United States				Eastern Mediter-ranean				West Africa				Other Int'l				United States				Intersegment Eliminations and Other (1)				Corporate
Year Ended December 31, 2019
Crude Oil Sales	$	2,736			$	2,437			$	6			$	293			$	—			$	—			$	—			$	—
NGL Sales	354				354				—				—				—				—				—				—
Natural Gas Sales	814				345				451				18				—				—				—				—
Total Crude Oil, NGL and Natural Gas Sales	3,904				3,136				457				311				—				—				—				—
Sales of Purchased Oil and Gas	389				109				—				—				—				190				—				90
Income (Loss) from Equity Method Investments and Other	51				8				—				61				—				(18		)		—				—
Midstream Services Revenues - Third Party	94				—				—				—				—				94								—
Intersegment Revenues	—				—				—				—				—				427				(427		)		—
Total Revenues	4,438				3,253				457				372				—				693				(427		)		90
Lease Operating Expense	532				460				37				76				—				4				(45		)		—
Production and Ad Valorem Taxes	175				169				—				—				—				6				—				—
Gathering, Transportation and Processing Expense	417				598				1				—				—				110				(292		)		—
Other Royalty Expense	13				13				—				—				—				—				—				—
Total Production Expense	1,137				1,240				38				76				—				120				(337		)		—
Exploration Expense	202				57				109				13				23				—				—				—
Depreciation, Depletion and Amortization	2,197				1,907				67				83				1				104				(29		)		64
Asset Impairments	1,160				1,160				—				—				—				—				—				—
Cost of Purchased Oil and Gas	431				107				—				—				—				181				—				143
Firm Transportation Exit Cost	88				—				—				—				—				—				—				88
Loss on Commodity Derivative Instruments	143				125				—				18				—				—				—				—
Loss on Debt Extinguishment	44				—				—				—				—				—				—				44
(Loss) Income Before Income Taxes	(1,776		)		(1,431		)		199				164				(25		)		258				(55		)		(886		)
Additions to Long-Lived Assets, Excluding Acquisitions	2,408				1,651				505				70				20				230				(92		)		24
Additions to Equity Method Investments	799				—				189				—				—				610				—				—
Property, Plant and Equipment, Net	17,451				11,859				3,041				793				44				1,721				(223		)		216
Year Ended December 31, 2018

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					Oil and Gas Exploration and Production																Midstream
(millions)	Consolidated				United States				Eastern Mediter-ranean				West Africa				Other Int'l				United States				Intersegment Eliminations and Other (1)				Corporate
Crude Oil Sales	$	2,945			$	2,548			$	7			$	390			$	—			$	—			$	—			$	—
NGL Sales	587				587				—				—				—				—				—				—
Natural Gas Sales	929				435				473				21				—				—				—				—
Total Crude Oil, NGL and Natural Gas Sales	4,461				3,570				480				411				—				—				—				—
Sales of Purchased Oil and Gas	275				20				—				—				—				142				—				113
Income from Equity Method Investments and Other	172				—				—				132				—				40				—				—
Midstream Services Revenues - Third Party	78				—				—				—				—				78				—				—
Intersegment Revenues	—				—				—				—				—				351				(351		)		—
Total Revenues	4,986				3,590				480				543				—				611				(351		)		113
Lease Operating Expense	576				480				26				97				—				—				(27		)		—
Production and Ad Valorem Taxes	190				184				—				—				—				6				—				—
Gathering, Transportation and Processing Expense	393				533				—				—				—				95				(235		)		—
Other Royalty Expense	38				38				—				—				—				—				—				—
Total Production Expense	1,197				1,235				26				97				—				101				(262		)		—
Exploration Expense	129				48				7				6				68				—				—				—
Depreciation, Depletion and Amortization	1,934				1,642				60				115				2				87				(20		)		48
(Gain) Loss on Divestitures, Net	(843		)		36				(376		)		—				—				(503		)		—				—
Asset Impairments	206				169				—				—				—				37				—				—
Goodwill Impairment	1,281				1,281				—				—				—				—				—				—
Cost of Purchased Oil and Gas	296				20				—				—				—				136				—				140
Gain on Asset Retirement Obligation Revision	(25		)		—				(8		)		—				(17		)		—				—				—
(Gain) Loss on Commodity Derivative Instruments	(63		)		(70		)		—				7				—				—				—				—
Income (Loss) Before Income Taxes	140				(875		)		742				305				(53		)		726				(60		)		(645		)
Additions to Long Lived Assets, Excluding Acquisitions	3,253				2,115				671				12				—				521				(91		)		25
Property, Plant and Equipment, Net	18,419				13,044				2,630				805				37				1,742				(145		)		306
Year Ended December 31, 2017
Crude Oil Sales	$	2,346			$	1,993			$	6			$	347			$	—			$	—			$	—			$	—
NGL Sales	493				493				—				—				—				—				—				—
Natural Gas Sales	1,221				670				528				23				—				—				—				—
Total Crude Oil, NGL and Natural Gas Sales	4,060				3,156				534				370				—				—				—				—
Income from Equity Method Investments and Other	177				—				—				120				—				57				—				—
Midstream Services Revenues - Third Party	19				—				—				—				—				19				—				—
Intersegment Revenues	—				—				—				—				—				277				(277		)		—

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					Oil and Gas Exploration and Production																Midstream
(millions)	Consolidated				United States				Eastern Mediter-ranean				West Africa				Other Int'l				United States				Intersegment Eliminations and Other (1)				Corporate
Total Revenues	4,256				3,156				534				490				—				353				(277		)		—
Lease Operating Expense	571				466				29				90				—				—				(14		)		—
Production and Ad Valorem Taxes	118				115				—				—				—				3				—				—
Gathering, Transportation and Processing Expense	432				550				—				—				—				70				(188		)		—
Other Royalty Expense	20				20				—				—				—				—				—				—
Total Production Expense	1,141				1,151				29				90				—				73				(202		)		—
Exploration Expense	188				102				2				5				79				—				—				—
Depreciation, Depletion and Amortization	2,053				1,739				76				146				4				30				(5		)		63
Loss on Marcellus Shale Upstream Divestiture and Other	2,379				2,286				—				—				—				—				—				93
Gain on Divestitures, Net	(326		)		(325		)		(1		)		—				—				—				—				—
Asset Impairments	70				63				—				—				7				—				—				—
Clayton Williams Energy Acquisition Expenses	100				100				—				—				—				—				—				—
Gain on Asset Retirement Obligation Revision	(42		)		—				—				—				(42		)		—				—				—
(Gain) Loss on Commodity Derivative Instruments	(63		)		(92		)		—				29				—				—				—				—
Loss on Debt Extinguishment	98				—				—				—				—				—				—				98
(Loss) Income Before Income Taxes	(2,191		)		(2,365		)		413				203				(54		)		233				(62		)		(559		)
Additions to Long Lived Assets, Excluding Acquisitions	2,851				1,994				411				34				(34		)		423				(79		)		102
Property, Plant and Equipment, Net	17,502				13,348				2,005				863				25				1,027				(74		)		308

(1)

Intersegment eliminations related to income (loss) before income taxes are the result of Midstream expenditures. Certain of these expenditures 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. Other expenditures are presented as production expense. Intercompany revenues and expenses are eliminated upon consolidation.

Note 4. Acquisitions and Divestitures

Year Ended December 31, 2019

Divestiture of Reeves County Assets In February 2019, we sold approximately 13,000 net proved and unproved non-core acres in the Reeves County, Texas area of the Delaware Basin. We received cash consideration of approximately $131 million, recognizing no gain or loss on the sale.

Asset Sale to Noble Midstream Partners In November 2019, we sold substantially all of our remaining midstream interests and assets to Noble Midstream Partners. The value of the transaction, which also included the sale of our incentive distribution rights, totaled approximately $1.6 billion, comprised of $670 million of cash and 38.5 million of newly issued Noble Midstream Partners common units, valued at approximately $930 million. Noble Midstream Partners funded the cash portion of the consideration through $420 million of borrowings on the Noble Midstream Services Revolving Credit Facility (defined below) and approximately $250 million in gross proceeds from a private placement of approximately 12 million common units. At closing, we owned approximately 56.5 million common units, or 63%, of the outstanding units of Noble Midstream Partners. We are subject to a post-closing 180-day lock-up period applicable to the common units received. Sales proceeds were used to repay amounts outstanding under our commercial paper program. As we continue to consolidate Noble Midstream Partners, the activities related to these assets will continue to be reflected within our Midstream segment.

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Year Ended December 31, 2018

Divestiture of Gulf of Mexico Assets  We sold substantially all of our Gulf of Mexico assets, including interests in producing properties and undeveloped acreage, for cash consideration of $480 million, along with the assumption, by the purchaser, of abandonment obligations associated with the properties sold. We recorded impairment expense of $168 million during first quarter 2018. We received net proceeds of approximately $384 million and recorded a loss of $24 million upon close.

Divestiture of 7.5% Interest in Tamar Field In first quarter 2018, we sold a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd. (Tamar Petroleum), a publicly traded entity on the Tel Aviv Stock Exchange (TASE: TMRP). Total consideration included cash of $484 million and 38.5 million of Tamar Petroleum shares that had a publicly traded value of $224 million. Total consideration received from the sale was applied to the field's basis and resulted in the recognition of a pre-tax gain of $376 million. We incurred tax expense of $86 million in connection with the transaction.

The Tamar Petroleum shares were subject to certain temporary lock-up provisions and had no voting rights. Due to the lock-up provisions associated with the Tamar Petroleum shares, we initially attributed $190 million of fair value to the shares, or 15% less than the publicly traded value on the TASE. These shares were accounted for at fair value and we recorded decreases in fair value of $27 million and dividend income of $31 million during 2018. These amounts are included in other non-operating (income) expense, net, in our consolidated statements of operations. In fourth quarter 2018, we sold the Tamar Petroleum shares in over the counter transactions for pre-tax proceeds of $163 million, net of transaction expenses.

Divestiture of Southwest Royalties In January 2018, we sold our investment in Southwest Royalties, Inc., which we acquired in the 2017 acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition). We received proceeds of $60 million, resulting in no gain or loss recognition on the sale of these assets.

Divestiture of Greeley Crescent Assets In September 2018, we sold assets in the Greeley Crescent area of the DJ Basin and received proceeds of $68 million, resulting in no gain or loss recognition on the sale of these assets.

Divestiture of Non-Core Delaware Basin Acreage In December 2018, we sold certain non-core acreage in the Delaware Basin, receiving proceeds of $63 million, resulting in a pre-tax loss of $16 million.

DJ Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 12,900 net undeveloped acres within core areas of our Mustang and Wells Ranch positions in exchange for approximately 12,300 net undeveloped acres in non-core areas of Mustang and Wells Ranch. No gain or loss was recognized.

Noble Midstream Partners Saddle Butte Acquisition In January 2018, Noble Midstream Partners and its partner formed Black Diamond Gathering LLC (Black Diamond) to acquire Saddle Butte Rockies Midstream, LLC and affiliates, which own a large-scale integrated gathering system located in the DJ Basin. Consideration for the acquisition totaled $681 million, which included $663 million of cash and assumption of $18 million of liabilities. Our partner funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of shareholders' equity, and Noble Midstream Partners funded the remainder.

We accounted for the transaction as a business combination using the acquisition method and allocated the total purchase price to assets acquired and liabilities assumed based on the fair values at the acquisition date. Allocated fair values included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill.

We own a 54.4% interest in Black Diamond and consolidate the entity as a VIE, reflecting the third-party ownership within noncontrolling interests in our consolidated statements of shareholders' equity.

Year Ended December 31, 2017

Clayton Williams Energy Acquisition We completed the Clayton Williams Energy Acquisition on April 24, 2017. Total consideration of $2.5 billion included cash consideration of $637 million and proceeds from the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion. In exchange, we received all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants.

In connection with the acquisition, we incurred acquisition-related costs of $100 million, including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees and $36 million of noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our consolidated statements of operations.

The transaction was accounted for as a business combination using the acquisition method. The allocation of the total purchase price of Clayton Williams Energy to the assets acquired and the liabilities assumed was based on the fair values at the

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acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. The $1.3 billion of goodwill recorded as part of the transaction was fully impaired in fourth quarter 2018.

The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations for 2019 and 2018. Revenues of $99 million and pre-tax net loss of $19 million were generated from Clayton Williams Energy assets during the period April 24, 2017 to December 31, 2017.

Marcellus Shale Upstream Divestiture In 2017, we sold all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The sales price totaled $1.2 billion, and we received $1.0 billion of net cash proceeds, after consideration of customary closing adjustments. The sales price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each for each annual period through 2020, should certain conditions be met. No amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition.

We recognized a loss on divestiture of $2.3 billion, or $1.5 billion after-tax, and recorded exit costs for retained financial commitments of $93 million, discounted. The aggregate net book value of the properties sold was approximately $3.4 billion, which included approximately $883 million of undeveloped leasehold cost.

After the property sale, we retained certain firm transportation commitments to flow Marcellus Shale natural gas production. See Note 11. Exit Cost – Transportation Commitments.

Other US Onshore Transactions We conducted the following additional transactions in 2017:

•	sold certain US onshore properties receiving total proceeds of $671 million, 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.

•	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.

•	acquired Delaware Basin properties, including seven producing wells, increasing our contiguous acreage position in the Reeves County, Texas area. Consideration totaled $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost.

Asset Sale to Noble Midstream Partners In June 2017, we sold interests in certain midstream assets to Noble Midstream Partners for $270 million, which consisted of $245 million in cash and 562,430 Noble Midstream Partners common units. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units, $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility and the remainder from cash on hand.

See Supplemental Oil and Gas Information (Unaudited) for discussion of proved reserves acquired or divested in connection with the above transactions.

Note 5. Equity Method Investments

The carrying values of our equity method investments, including the respective segments, are as follows:

					December 31,
(millions, except percentages)	Segment		Ownership		2019				2018
Eastern Mediterranean Pipeline B.V.	Eastern Mediterranean		25%		$	189			$	—
Atlantic Methanol Production Company, LLC and Affiliates(1)	West Africa		45%		160				146
Alba Plant LLC (2)	West Africa		28%		56				58
EPIC Y-Grade, LP	Midstream		15%		166				—
EPIC Crude Holdings, LP	Midstream		30%		339				—
Delaware Crossing LLC	Midstream		50%		69				—
Advantage Pipeline, L.L.C.	Midstream		50%		77				73
Other	N/A		N/A		10				9
Total Equity Method Investments (3)					$	1,066			$	286

(1)	Atlantic Methanol Production Company, LLC (AMPCO) owns and operates a methanol plant and related facilities in Equatorial Guinea.

(2)	Alba Plant LLC owns and operates a LPG processing plant in Equatorial Guinea.

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(3)	At December 31, 2019, total carrying values were $42 million higher than the underlying net assets of the investments, primarily due to capitalized interest which is amortized into earnings over the useful life of the related assets.

At December 31, 2019, consolidated retained earnings included $73 million related to the undistributed earnings of equity method investments.

Acquisitions and Divestitures

Year Ended December 31, 2019

EMED Pipeline B.V. During third quarter 2019, we acquired a 25% equity interest in Eastern Mediterranean Pipeline B.V. (EMED Pipeline B.V.). In fourth quarter 2019, EMED Pipeline B.V. acquired an approximate 39% equity interest in East Mediterranean Gas Company S.A.E. (EMG), which owns the EMG Pipeline. Upon closing of EMED Pipeline B.V.'s equity acquisition of EMG, we own an effective, indirect interest of approximately 10%, net, in EMG. The EMG Pipeline provides connection from the Israel pipeline network to Egyptian customers and supports delivery of natural gas from our producing fields offshore Israel into Egypt. During 2019, we made capital contributions of $189 million in EMED Pipeline B.V., primarily to fund the EMG equity acquisition.

EPIC Pipelines In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which constructed the EPIC Y-Grade Pipeline, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC Crude Oil Pipeline. The pipelines support transportation of production from the Delaware Basin to Corpus Christi, Texas. Noble Midstream Partners made capital contributions of $169 million and $351 million in EPIC Y-Grade and EPIC Crude Holdings, respectively, in 2019.

Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners formed a 50/50 joint venture with Salt Creek Midstream LLC. The joint venture, Delaware Crossing LLC, is constructing a crude oil pipeline system in the Delaware Basin. Noble Midstream Partners made capital contributions of $70 million for its share of pipeline construction costs in 2019.

Year Ended December 31, 2018

Divestiture of Marcellus Shale CONE Gathering In January 2018, we sold our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $309 million in cash and recognized a pre-tax gain of $196 million. After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During 2018, we sold our 21.7 million common units, receiving net proceeds of approximately $387 million, and recognized a gain of $307 million. The investment was previously accounted for under the equity method of accounting.

Year Ended December 31, 2017

Noble Midstream Partners Advantage Joint Venture In April 2017, Noble Midstream Partners acquired a 50% interest in Advantage Pipeline, L.L.C. (Advantage Pipeline) for $67 million. Advantage Pipeline owns a crude oil pipeline system in the southern Delaware Basin from Reeves County, Texas to Crane County, Texas, for which we serve as operator.

Combined Financial Information

Summarized, 100% combined balance sheet information for equity method investments was as follows:

	December 31,
(millions)	2019				2018
Current Assets	$	681			$	387
Noncurrent Assets	5,306				575
Current Liabilities	607				198
Noncurrent Liabilities	2,243				81

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Summarized, 100% combined statements of operations for equity method investments was as follows:

	Year Ended December 31,
(millions)	2019				2018				2017
Operating Revenues	$	1,018			$	855			$	790
Operating Expenses	853				284				303
Operating Income	165				571				487
Other (Loss) Income, net	(33		)		3				15
Income Before Income Taxes	132				574				502
Income Tax Provision	72				152				136
Net Income	$	60			$	422			$	366

Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs

Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. These costs are included in Oil and Gas Properties on our consolidated balance sheets. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.

Changes in capitalized exploratory well costs, excluding amounts that were capitalized and subsequently expensed in the same period, are as follows:

	Year Ended December 31,
(millions)	2019				2018				2017
Capitalized Exploratory Well Costs, Beginning of Period	$	354			$	520			$	768
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves	26				7				20
Divestitures (1)	—				(168		)		—
Reclassified to Proved Oil and Gas Properties, Based on Determination of Proved Reserves, or to Assets Held for Sale (2)	—				(1		)		(203		)
Capitalized Exploratory Well Costs Charged to Expense (3)	(100		)		(4		)		(65		)
Capitalized Exploratory Well Costs, End of Period	$	280			$	354			$	520

(1)	The 2018 amount relates to the second quarter 2018 sale of our Gulf of Mexico assets.

(2)	The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field.

(3)

In fourth quarter 2019, we recorded exploration expense of $100 million related to the Leviathan Deep prospect, offshore Israel, which was initially drilled in 2012 but did not reach the target interval. Throughout this time, we have evaluated seismic information and nearby discoveries in the region. Upon concluding we would not move forward with the project, we wrote off the entire amount of capitalized exploratory well costs associated with this prospect. The 2017 amount relates to a write-off of costs for a natural gas discovery in the Gulf of Mexico. See Note 10. Impairments.

The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:

	December 31,
(millions, except number of projects)	2019				2018				2017
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	22			$	6			$	10
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling	258				348				510
Balance at End of Period	$	280			$	354			$	520
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling	5				7				8

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The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2019:

					Suspended Since
(millions)	Total				2017 - 2018				2015 - 2016				2014 & Prior				Progress
Offshore Eastern Mediterranean
Dalit (Offshore Israel)	$	23			$	(9	)		$	3			$	29			Our future development plan for this 2008 natural gas discovery, consisting of a tie-in to existing infrastructure at Tamar, was approved by the Government of Israel in 2019. During 2019, we continued analyzing 3D seismic data to evaluate additional potential of the area.
Cyprus (Offshore Cyprus)	100				3				15				82				During 2019, we received approval of our Plan of Development and Exploitation License from the Government of Cyprus. We continued to progress capital project cost improvement and regional natural gas marketing efforts.
Offshore West Africa
Felicita (Block O, Offshore Equatorial Guinea)	49				2				4				43				We are in the process of evaluating regional development scenarios for this 2008 natural gas discovery. The recent sanction of the Alen Gas Monetization project, which represents the initial step in establishing a regional natural gas hub, expands the options for development of this discovery through existing infrastructure.
YoYo (YoYo Block, Offshore Cameroon) and Yolanda (Block I, Offshore Equatorial Guinea)	80				2				5				73				A data exchange agreement for these 2007 condensate and natural gas discoveries has been executed between the governments of Equatorial Guinea and Cameroon. Our development team is working with both governments to evaluate natural gas monetization options. The recent sanction of the Alen Gas Monetization project, which represents the initial step in establishing a regional natural gas hub, expands the options for development of this discovery through existing infrastructure.
Other
Projects less than $20 million	6				(1		)		(10		)		17				Continuing to assess and evaluate wells.
Total	$	258			$	(3	)		$	17			$	244

Undeveloped Leasehold Costs  Changes in undeveloped leasehold costs, which are recorded in oil and gas properties on our consolidated balance sheets, were as follows:

	Year Ended December 31,
(millions)	2019				2018
Undeveloped Leasehold Costs, Beginning of Period	$	2,373			$	2,922
Additions to Undeveloped Leasehold Costs	59				47
Transfers to Proved Properties (1)	(184		)		(453		)
Assets Sold (2)	(96		)		(142		)
Impairment	—				(1		)
Undeveloped Leasehold Costs, End of Period	$	2,152			$	2,373

(1)	Transfers primarily relate to development of Delaware Basin assets.

(2)	Amounts primarily relate to Delaware Basin assets sold. See Note 4. Acquisitions and Divestitures.

As of December 31, 2019, undeveloped leasehold costs included $1.9 billion, $100 million, $79 million, and $58 million attributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties, and international properties, respectively. Certain of these costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. Other costs pertain to acreage that is being held by production.

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Note 7. Asset Retirement Obligations

Asset retirement obligations (ARO) consists primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows:

	Year Ended December 31,
(millions)	2019				2018
Asset Retirement Obligations, Beginning of Period	$	880			$	875
Liabilities Incurred	70				25
Liabilities Settled	(110		)		(345		)
Revisions of Estimates	(69		)		293
Reclassification to Liabilities Associated with Assets Held for Sale	—				(1		)
Accretion Expense	43				33
Asset Retirement Obligations, End of Period	$	814			$	880

Year Ended December 31, 2019 Liabilities incurred included $43 million in Israel, primarily related to costs associated with the Leviathan field, and $20 million in US onshore, primarily related to the DJ and Delaware Basins. The majority of liabilities settled relate to abandonment of properties in the DJ Basin where we have engaged in a program to plug and abandon older vertical wells. Costs associated with these abandonment activities will be incurred over several years. Revisions of estimates include a decrease of $72 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells.

Year Ended December 31, 2018 Liabilities settled included $216 million and $24 million of liabilities assumed by the purchasers of the Gulf of Mexico properties and Greeley Crescent assets, respectively, and $104 million related to abandonment of US onshore properties, primarily in the DJ Basin, where we have engaged in a program to plug and abandon older vertical wells, as discussed above.

Revisions of estimates were primarily related to increases in cost estimates and changes in timing estimates of $287 million for US onshore, primarily in the DJ Basin related to the abandonment activities noted above, $10 million for wells offshore Israel and $9 million for wells offshore Equatorial Guinea, partially offset by decreases in cost and timing estimates of $17 million associated with the North Sea abandonment project.

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Note 8. Long-Term Debt

Our debt consists of the following:

	December 31, 2019							December 31, 2018
(millions, except percentages)	Debt				Interest Rate			Debt				Interest Rate
Noble Energy, Excluding Noble Midstream Partners
Revolving Credit Facility, due March 9, 2023	$	—			—	%		$	—			—	%
Commercial Paper Borrowings	—				—	%		—				—	%
Senior Notes, due December 15, 2021	—				—	%		1,000				4.15	%
Senior Notes, due October 15, 2023	100				7.25	%		100				7.25	%
Senior Notes, due November 15, 2024	650				3.90	%		650				3.90	%
Senior Notes, due April 1, 2027	250				8.00	%		250				8.00	%
Senior Notes, due January 15, 2028	600				3.85	%		600				3.85	%
Senior Notes, due October 15, 2029	500				3.25	%		—				—	%
Senior Notes, due March 1, 2041	850				6.00	%		850				6.00	%
Senior Notes, due November 15, 2043	1,000				5.25	%		1,000				5.25	%
Senior Notes, due November 15, 2044	850				5.05	%		850				5.05	%
Senior Notes, due August 15, 2047	500				4.95	%		500				4.95	%
Senior Notes, due October 15, 2049	500				4.20	%		—				—	%
Senior Debentures	84				7.25	%		92				7.13	%
Finance Lease Obligations	205				—	%		223				—	%
Total Noble Energy Debt, Excluding Noble Midstream Partners Debt	6,089							6,115
Noble Midstream Partners
Noble Midstream Services Revolving Credit Facility, due March 9, 2023	595				3.11	%		60				3.67	%
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021	500				2.85	%		500				3.42	%
Noble Midstream Services Term Loan Credit Facility, due August 23, 2022	400				2.74	%		—				—	%
Total Noble Midstream Partners Debt	1,495							560
Total Debt	7,584							6,675
Net Unamortized Discounts and Debt Issuance Costs	(65		)					(60		)
Total Debt, Net of Unamortized Discounts and Debt Issuance Costs	$	7,519						$	6,615
Less Amounts Due Within One Year:
Finance Lease Obligations	(42		)					(41		)
Long-Term Debt Due After One Year	$	7,477						$	6,574

Revolving Credit Facility  Our Credit Agreement, as amended, provides for a $4.0 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating, and (iii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility. As of December 31, 2019, we were in compliance with our debt covenants and no amounts were outstanding under our Revolving Credit Facility.

Commercial Paper Program Our commercial paper program provides for short-term funding needs. The program allows Noble Energy to issue a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s $4.0 billion Revolving Credit Facility. Our commercial paper notes, which generally have a maturity of less than 30 days, are sold under customary terms in the commercial paper market and are generally issued at a discounted price relative to the principal face value. Such discount prices are dependent on market conditions and ratings assigned to the commercial paper program by credit rating agencies at the time of commercial paper issuance. As of December 31, 2019, we had no outstanding commercial paper borrowings.

Senior Notes Issuance and Completed Tender Offer On October 1, 2019, we issued $500 million of 3.25% senior notes due

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October 15, 2029 and $500 million of 4.20% senior notes due October 15, 2049. Interest on the notes is payable semi-annually beginning April 15, 2020. We may redeem some or all of the notes at any time at the applicable redemption price, plus accrued interest, if any. Proceeds from the issuance of the notes were used to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we recorded early debt extinguishment cost of approximately $44 million in our consolidated statements of operations.

Noble Midstream Services Revolving Credit Facility Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, maintains a revolving credit facility (Noble Midstream Services Revolving Credit Facility), which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners. In fourth quarter 2019, the capacity of the facility was increased from $800 million to almost $1.2 billion. As of December 31, 2019, $555 million was available for borrowing under the Noble Midstream Services Revolving Credit Facility.

All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Services Revolving Credit Facility, are guaranteed by Noble Midstream Partners and all wholly-owned material subsidiaries of Noble Midstream Partners. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019.

Noble Midstream Services 2019 Term Loan Credit Facility On August 23, 2019, Noble Midstream Services entered into a term loan agreement (Noble Midstream Services 2019 Term Credit Agreement), which provides for a three-year senior unsecured term loan credit facility due August 23, 2022 (2019 Term Loan Credit Facility) with permitted aggregate borrowings of up to $400 million. Proceeds from the 2019 Term Loan Credit Facility were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019.

Noble Midstream Services 2018 Term Loan Credit Facility In 2018, Noble Midstream Services entered into a term loan agreement (Noble Midstream Services 2018 Term Credit Agreement), which provides for a three-year senior unsecured term loan credit facility due July 31, 2021 (2018 Term Loan Credit Facility) with permitted aggregate borrowings of up to $500 million. Proceeds from the 2018 Term Loan Credit Facility were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019.

Fair Value of Debt The fair value of fixed-rate, public debt is estimated based on the published market prices. As such, we consider the fair value of this debt to be a Level 1 measurement on the fair value hierarchy. Our non-public debt, including our Revolving Credit Facility, commercial paper borrowings, Noble Midstream Services Revolving Credit Facility and Noble Midstream Services term loans are subject to variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the fair value to be a Level 2 measurement on the fair value hierarchy. Fair value information regarding our debt is as follows:

	December 31, 2019								December 31, 2018
(millions)	Carrying Amount				Fair Value				Carrying Amount				Fair Value
Debt	$	7,379			$	8,033			$	6,452			$	6,121

Annual Debt Maturities   As of December 31, 2019, annual maturities of outstanding debt, excluding finance lease obligations, were as follows:

	Debt Principal Payments
(millions)	Noble Energy Excluding Noble Midstream Partners				Noble Midstream Partners				Total
2020	$	—			$	—			$	—
2021	—				500				500
2022	—				400				400
2023	100				595				695
2024	650				—				650
Thereafter	5,134				—				5,134
Total	$	5,884			$	1,495			$	7,379

Finance Lease Obligations   See Note 9. Leases.

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Note 9. Leases

In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest.

Balance Sheet Information ROU assets and lease liabilities are as follows:

(millions)	Balance Sheet Location	December 31, 2019
ROU Assets
Operating Leases (1)	Other Noncurrent Assets	$	227
Finance Leases (2)	Total Property, Plant and Equipment, Net	172
Total ROU Assets		$	399
Lease Liabilities
Current Liabilities
Operating Leases	Other Current Liabilities	$	88
Finance Leases	Other Current Liabilities	42
Noncurrent Liabilities
Operating Leases	Other Noncurrent Liabilities	164
Finance Leases	Long-Term Debt	163
Total Lease Liabilities		$	457

(1)	Operating lease ROU assets include compressors of $89 million and office space of $80 million.

(2)	Finance lease ROU assets include office space of $90 million and a trunkline of $28 million, both net of accumulated amortization.

Statement of Operations Information The components of lease cost are as follows:

(millions)	Statement of Operations Location	Year Ended December 31, 2019
Operating Lease Cost	Various (1)	$	110
Finance Lease Cost
Amortization Expense	Depreciation, Depletion and Amortization	38
Interest Expense	Interest, Net of Amount Capitalized	13
Short-term Lease Cost (2)	Various (1)	424
Sublease Income	General and Administrative	(5		)
Total Lease Cost		$	580

(1)	Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and therefore, are included as part of oil and gas properties on our consolidated balance sheets.

(2)	Costs primarily relate to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less.

Cash Flow Information Supplemental cash flow information is as follows:

	Year Ended December 31, 2019
(millions)	Operating Leases				Finance Leases
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows	$	74			$	12
Investing Cash Flows	36				—
Financing Cash Flows	—				42
Non-Cash Activities
ROU Assets Obtained in Exchange for Lease Liabilities (1)	127				26

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(1)	Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 1. Summary of Significant Accounting Policies.

Annual Lease Maturities As of December 31, 2019, maturities of lease liabilities were as follows:

(millions)	Operating Leases				Finance Leases				Total
2020	$	100			$	52			$	152
2021	60				38				98
2022	41				27				68
2023	26				23				49
2024	15				21				36
2025 and Thereafter	37				86				123
Total Lease Liabilities, Undiscounted	279				247				526
Less: Imputed Interest	27				42				69
Total Lease Liabilities (1)	$	252			$	205			$	457

(1)	Includes the current portions of $88 million and $42 million for operating and finance leases, respectively.

Lease Commitments See Note 12. Commitments and Contingencies for lease commitments as of December 31, 2019.

Other Information As of December 31, 2019, other information related to our leases is as follows:

	Operating Leases			Finance Leases
Weighted-Average Remaining Lease Term	4.9 years			7.5 years
Weighted-Average Discount Rate	4.05	%		4.96	%

Note 10. Impairments

2019 Impairments In fourth quarter 2019, we determined that the continued depressed commodity price environment and performance of certain of our US onshore basins indicated possible impairment of our proved oil and gas properties in our US onshore business. Following our impairment analysis, we recorded impairment expense of $1.2 billion to our Eagle Ford Shale proved properties, primarily as a result of significant decreases in NGL and natural gas prices, partially offset by lower capital and operating costs. The fair value of approximately $600 million was estimated using the income approach, utilizing a discounted cash flow model. The cash flow model included management's estimates of future production, commodity prices based on published forward commodity price curves, operating and development costs, and a risk-adjusted discount rate. As of December 31, 2019, we had $100 million of undeveloped leasehold costs related to our Eagle Ford Shale unproved properties that were not impaired and for which we believe future development scenarios exist to recover these costs.

2018 Impairments In 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized impairment expense of $168 million. Additionally, in fourth quarter 2018, we recorded impairment expense of $38 million, $37 million of which related to changes in construction plans for certain midstream assets.

In fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increases in operating and capital costs, as well as our development plans, and concluded that it was more likely than not that the fair value of our Texas reporting unit was less than its carrying amount. As a result, we recognized a goodwill impairment of $1.3 billion.

Note 11. Exit Cost – Transportation Commitments

In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain long-term financial commitments to pay transportation fees on certain pipelines in the Marcellus Basin. As of December 31, 2019, our undiscounted financial commitment for the remaining obligations under these agreements, which have remaining terms of three to fourteen years, was approximately $1.0 billion, which excludes the impact of ongoing mitigation activities to reduce and offset this cost. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies.

Our efforts to mitigate and thereby reduce these obligations primarily include permanent assignment of capacity, negotiation of capacity releases and utilization of capacity through purchase and transport of third-party natural gas. Revenues and expenses associated with mitigation activities are recorded in sales of purchased oil and gas and cost of purchased oil and gas, respectively, in our consolidated statements of operations. In the event we execute a permanent assignment of capacity, we no

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longer have a contractual obligation to the pipeline company and, as such, our gross financial commitment is reduced. In the event we execute a capacity release or utilize the capacity through the purchase and transport of third-party natural gas, we remain the primary obligor to the pipeline company. While our gross financial commitment is not reduced, except through use under those arrangements, we would receive future cash payments from the third-parties with whom we negotiated a capacity release or from the sale of purchased natural gas to third-parties. As a result of our mitigation activities, we reduced and offset our financial obligations by approximately $38 million and $8 million in 2019 and 2018, respectively.

Leach Xpress and Rayne Xpress Permanent Assignment In January 2019, we executed agreements on the Leach Xpress and Rayne Xpress pipelines to permanently assign the remaining capacity to a third-party effective January 1, 2021, extending through the remainder of the contract. The permanent assignment reduced our total financial commitment by approximately $350 million, undiscounted. As a result of the assignment, we recorded firm transportation exit cost at a fair value $92 million, representing the discounted, present value of our remaining obligation to the third-party. We will continue efforts to mitigate the impact of these transportation agreements through 2020.

Exit Costs Reconciliation of accrued exit costs at December 31, 2019 is as follows:

		December 31,
(millions)		2019				2018
Balance at Beginning of Period		$	80			$	90
Exit Cost Accrual(1)		88				—
Payments, Net of Accretion		(5		)		(10		)
Balance at End of Period		$	163			$	80
Less Current Portion Included in Other Current Liabilities		34				13
Long-term Portion Included in Other Noncurrent Liabilities		$	129			$	67

(1)	Amount includes $92 million exit cost for the permanent assigned discussed above, offset by a gain of $4 million.

Revenues and expenses associated with these long-term financial commitments, including mitigation activities discussed above, were as follows:

		Year Ended December 31,
(millions)		2019				2018				2017
Sales of Purchased Gas		$	90			$	113			$	—
Cost of Purchased of Gas		85				108				—
Utilized Firm Transportation Expense		57				29				—
Unutilized Firm Transportation Expense		1				3				—
Cost of Purchased Gas, Total		$	143			$	140			$	—

Note 12. Commitments and Contingencies

Legal Proceedings   We are involved in various legal proceedings in the ordinary course of business.  These proceedings are subject to the uncertainties inherent in any litigation.  We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.

Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency (EPA), US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $4 million and supplemental environmental project costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief, including plugging and abandonment of certain wells and facilities, are also being expended in accordance with schedules established in the Consent Decree.

We have concluded that the penalties, injunctive relief and mitigation expenditures that result from this settlement, based on currently available information, will not have a material adverse effect on our financial position, results of operations or cash flows. See Note 7. Asset Retirement Obligations.

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Colorado Water Quality Control Division Matter In October 2019, we resolved by Compliance Order on Consent (COC) with the Colorado Department of Public Health & Environment allegations of noncompliance with the Colorado Water Quality Act relating to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and/or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado. The COC required us to pay a penalty of $57 thousand and to contribute $126 thousand toward a State-managed supplemental environmental project. We have concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows.

Colorado Clean Water Act Referral Notice  In September 2018, we received a letter from the US Department of Justice providing notification of referral from the EPA of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. In April 2019, we met with the DOJ and Environmental Protection Agency enforcement personnel to discuss potential settlement of the alleged violations. Given the ongoing status of settlement discussions, we are currently unable to predict the ultimate outcome of this action, but believe the resolution will not have a material adverse effect on our financial position, results of operations or cash flows.

Marcellus Shale Firm Transportation Obligations As part of our Marcellus Shale upstream divestiture, we retained certain transportation obligations to flow Marcellus Shale natural gas production to various markets. See Note 11. Exit Cost – Transportation Commitments.

Other Gathering and Transportation Obligations As part of our normal course of business, we enter into agreements to transport minimum volumes in the US onshore and Eastern Mediterranean. In the US onshore, primarily in the DJ Basin, certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments and will incur expense related to volume deficiencies and/or unutilized commitments. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. These amounts are recorded as marketing expense in our consolidated statements of operations. In the Eastern Mediterranean, regional export contracts contain minimum transportation commitments. For US onshore and Eastern Mediterranean agreements, which have remaining terms of one to 12 years, our total financial commitment is approximately $921 million, undiscounted. The commitments are included in the table below.

Mezzanine Equity Commitment In March 2019, Noble Midstream Partners obtained a $200 million preferred equity commitment. $100 million of the commitment funded immediately and the remaining $100 million is available for funding until March 2020, subject to certain conditions precedent. See Note 1. Summary of Significant Accounting Policies and Note 4. Acquisitions and Divestitures.

Minimum Commitments Minimum commitments as of December 31, 2019 consist of the following:

(millions)	Purchase and Service Obligations				Marcellus Shale Firm Transportation Obligations (1)				Gathering, Transportation & Processing Obligations (2)				Operating Lease Obligations (3)				Finance Lease Obligations (3)				Total
2020	$	135			$	143			$	174			$	100			$	52			$	604
2021	28				102				176				60				38				404
2022	14				85				156				41				27				323
2023	30				83				153				26				23				315
2024	2				92				149				15				21				279
2025 and Thereafter	72				675				334				37				86				1,204
Total	$	281			$	1,180			$	1,142			$	279			$	247			$	3,129

(1)	Amount includes exit cost obligations resulting from permanent capacity assignments. See Note 11. Exit Cost – Transportation Commitments.

(2)	Amount includes US onshore and Eastern Mediterranean transportation obligations of $921 million, undiscounted, and Noble Midstream Partners obligations of $221 million, undiscounted.

(3)	See Note 9. Leases.

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Note 13. Income Taxes

Components of (loss) income from operations before income taxes are as follows:

	Year Ended December 31,
(millions)	2019				2018				2017
Domestic	$	(2,222	)		$	(953	)		$	(2,831	)
Foreign	446				1,093				640
Total	$	(1,776	)		$	140			$	(2,191	)

Income Tax Provision The income tax (benefit) provision consists of the following:

	Year Ended December 31,
(millions, except percentages)	2019				2018				2017
Current Taxes
Federal	$	1			$	22			$	(11	)
State	3				2				1
Foreign	81				172				96
Total Current	$	85			$	196			$	86
Deferred Taxes
Federal	$	(413	)		$	(123	)		$	(1,258	)
State	(25		)		(7		)		(8		)
Foreign	10				60				39
Total Deferred	$	(428	)		$	(70	)		$	(1,227	)
Total Income Tax (Benefit) Provision Attributable to Noble Energy	$	(343	)		$	126			$	(1,141	)
Effective Tax Rate	19.3		%		90.0		%		52.1		%

The 2019 deferred income tax benefit relates to the asset impairment recorded in fourth quarter 2019. See Note 10. Impairments. The 2018 income tax provision is primarily due to current income tax expense for foreign taxes on the gain recognized for the 2018 divestiture of a 7.5% working interest in the Tamar field, partially offset by a deferred income tax benefit. The 2017 income tax benefit is due to the significant deferred tax benefit associated with the revaluation of the US deferred tax liability as a result of the reduction in the federal corporate tax rate to 21%.

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Effective Tax Rate (ETR) A reconciliation of the federal statutory tax rate to the ETR is as follows:

	Year Ended December 31,
(percentages)	2019			2018			2017
Federal Statutory Rate	21.0	%		21.0	%		35.0	%
Effect of
Goodwill Impairment	—			192.5			—
Change in Valuation Allowance	(0.6	)		(170.2	)		(17.4	)
US and Foreign Statutory Rate Change	—			80.7			23.5
Accumulated Undistributed Foreign Earnings	—			—			11.0
Transition Tax	—			—			(4.8	)
Difference Between US and Foreign Rates	(0.6	)		17.9			1.8
Earnings of Equity Method Investments	0.7			(20.1	)		1.9
Noncontrolling Interests	0.9			(12.1	)		1.1
State Taxes	1.1			0.9			0.3
Foreign Exploration Loss	—			(35.6	)		—
Global Intangible Low-Taxed Income (GILTI)	(0.8	)		24.2			—
Return to Provision	—			(17.1	)		(0.1	)
Audit Settlement	—			5.1			0.1
Oil Profits Tax - Israel	(0.1	)		3.3			(0.1	)
Other, Net	(2.3	)		(0.5	)		(0.2	)
Effective Rate	19.3	%		90.0	%		52.1	%

There were no material items impacting our 2019 ETR as compared to the federal statutory rate of 21%. Our 2018 ETR included a significant deferred tax benefit, discussed below, recorded as a result of the intent of the US Department of the Treasury (Treasury) and Internal Revenue Service (IRS) to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act (Tax Reform Legislation) and the transition tax. In addition, the 2018 ETR was impacted by low earnings, goodwill impairment with no tax benefit, deferred tax expense of $34 million related to GILTI, discussed below, and a deferred tax benefit of $50 million associated with a write-off of foreign exploration losses. Our 2017 ETR was driven by the deferred tax benefit related to the Tax Reform Legislation, as we revalued the ending deferred tax liability at the reduced future tax rate.

Deferred Tax Assets and Liabilities Deferred tax assets and liabilities resulted from the following:

	December 31,
(millions)	2019				2018
Deferred Tax Assets
Loss Carryforwards (1)	$	656			$	589
Employee Compensation and Benefits	92				92
Mark to Market of Commodity Derivative Instruments	11				(27		)
Foreign Tax Credits	133				138
Other	126				157
Total Deferred Tax Assets	$	1,018			$	949
Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits	(327		)		(320		)
Net Deferred Tax Assets	$	691			$	629
Deferred Tax Liabilities
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments	(1,338		)		(1,669		)
Total Deferred Tax Liability	$	(1,338	)		$	(1,669	)
Net Deferred Tax Liability	$	(647	)		$	(1,040	)

(1)	At December 31, 2019, $459 million related to domestic tax (state and federal) and $197 million related to foreign tax.

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Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:

	December 31,
(millions)	2019				2018
Deferred Income Tax Asset - Noncurrent	$	15			$	21
Deferred Income Tax Liability - Noncurrent	(662		)		(1,061		)
Net Deferred Tax Liability	$	(647	)		$	(1,040	)

Our estimated pre-tax net operating loss (NOL) carryforwards totaled approximately $2.7 billion at December 31, 2019, of which US federal income tax NOL carryforwards totaled approximately $2.0 billion and foreign NOL carryforwards totaled $691 million.

We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards and foreign tax credits. The valuation allowance on foreign loss carryforwards totaled $192 million and $187 million in 2019 and 2018, respectively. The valuation allowance on foreign tax credits totaled $133 million and $132 million in 2019 and 2018, respectively.

Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2019, there is no expected withholding tax impact upon actual distribution of earnings and as such, we have not recorded any tax associated with unremitted earnings.

Tax Reform Legislation Updates   Since the enactment of Tax Reform Legislation by the US Congress in December 2017, Treasury and the IRS have periodically issued guidance regarding various aspects of the new law.

Global Intangible Low-Taxed Income (GILTI) Tax Reform Legislation introduced a new tax on GILTI. Further analysis and legal interpretation has resulted in identifying certain foreign oil related income (FORI) activity as GILTI income which will be offset by NOL carryforwards rather than the 50% deduction and related foreign tax credits. As a result of utilizing our NOL to offset the GILTI inclusion, for 2019 and 2018, we recognized tax expense of $14 million and $34 million, respectively, of GILTI associated with FORI from investments in Equatorial Guinea and Israel.

In June 2019, Treasury and the IRS released new proposed regulations pertaining to GILTI, which include an election that would apply an elective high-tax exception to GILTI when the tax imposed on a tentative net tested income item exceeds an 18.5% corporate tax rate. The applicability of the high-tax exception would be tested at the level of a single qualified business unit (QBU) and would apply to all foreign corporations controlled by the same domestic shareholders. This regulation is applicable to taxable years beginning on or after the date that final regulations are published in the Federal Register. For us, this high tax exception would have the effect of reclassifying all GILTI into another classification of income, thus eliminating the GILTI/NOL offset item described above. We will continue to monitor the development of this proposed regulation.

Transition Tax (Toll Tax) Tax Reform Legislation provided for a toll tax on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. In April 2018, the Treasury and the IRS released Notice 2018-26, signaling intent to issue regulations related to the toll tax for the year ended December 31, 2017. This notice clarified that an Internal Revenue Code Section 965(n) election is available with respect to both current and prior year NOLs. As a result, we released $252 million of the valuation allowance recorded against foreign tax credits to be utilized against the estimated $268 million toll tax liability recorded as of December 31, 2017. This resulted in a $252 million tax benefit and a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized NOLs. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit.

During fourth quarter 2018, the toll tax calculations were finalized in conjunction with filing of the US tax return, resulting in a $261 million toll tax against which $240 million of foreign tax credits were utilized. This resulted in a $21 million liability payable in installments over eight years beginning in 2018.

Other Provisions Tax Reform Legislation broadened the former Section 163(j) applying a net interest expense limitation equal to 30% of earnings before interest, taxes, depreciation, and amortization (EBITDA) for tax years beginning after December 31, 2017, and before January 1, 2022, after which the net interest expense limitation will be calculated as 30% of earnings before interest and taxes (EBIT). Disallowed interest may be carried forward indefinitely. In November 2018, Treasury and the IRS released proposed regulations pertaining to section 163(j) which state that any amount normally incurred as deductible DD&A, but included in a taxpayer’s cost of goods sold calculation pursuant to section 263A, is not a deduction for DD&A for purposes of determining Adjusted Taxable Income for years beginning prior to January 1, 2022. We have modified our 163(j) limitation calculation to comply and will continue to monitor the development of this proposed regulation.

Israeli Tax Law   Our Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011 (the Law), which imposes a separate additional tax on profits from oil and gas activities (Oil Profits Tax). The Oil Profits Tax is calculated by dividing net accumulated revenue generated by each separate project by its cumulative investments as defined within the

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Law. Once the revenue factor (R Factor) reaches 1.5, a tax rate of 20% is imposed; as the ratio increases to a maximum of 2.3, the Oil Profits Tax increases progressively up to a maximum rate of 50%. The Oil Profits Tax provides for a corporate tax rate adjustment based on the corporate income tax rate, which is currently 23%. To the extent the corporate income tax rate exceeds 18%, a reduction in the Oil Profits Tax rate is calculated. At the current corporate tax rate, the Oil Profits Tax rate is 46.8%. The Oil Profits Tax is deductible for Israeli corporate tax purposes. Our Tamar and Leviathan projects are both subject to the Oil Profits Tax and are expected to pay at the maximum rate.

Clayton Williams Energy Acquisition In April 2017, we completed the Clayton Williams Energy Acquisition, which qualified as a tax free merger, and acquired carryover tax basis in Clayton Williams Energy's assets and liabilities. As part of our purchase price allocation we recorded a deferred tax liability of $307 million, adjusted for the new US statutory rate, which includes a deferred tax asset for federal pre-tax NOLs of approximately $450 million. The merger resulted in a change of control for federal income tax purposes, and the NOL usage will be subject to an annual limitation in part based on Clayton Williams Energy's value at the date of the merger.

Unrecognized Tax Benefits   We file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of audit results.

Note 14. Derivative Instruments and Hedging Activities

Objective and Strategies for Using Derivative Instruments   We enter into price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our production. The derivative instruments we use may include variable to fixed price commodity swaps, enhanced swaps, collars and three-way collars, sold calls and sold puts, basis swaps, swaptions and/or put options.

The fixed price swap and collar contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period.

A three-way collar consists of a collar contract combined with a put option contract sold by us with a strike price below the floor price of the collar.  We receive price protection at the purchased put option floor price of the collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the difference between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment.

A swaption gives counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates.

Sold calls are entered into to receive premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts. Sold puts are entered into to receive premiums for establishing a minimum price that would be settled for the notional volumes covered by basis swap contracts.

While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits during periods of increasing commodity prices. Additionally, derivative instruments expose us to counterparty credit risk, especially during periods of falling prices. Our commodity derivative instruments are currently with a diversified group of major banks or market participants. We monitor the creditworthiness of these counterparties and our internal hedge policies provide for exposure limits.

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Unsettled Commodity Derivative Instruments   As of December 31, 2019, we had entered into the following crude oil derivative instruments:

					Swaps							Collars
Settlement Period	Type of Contract	Index	Bbls per Day		Weighted Average Differential			Weighted Average Fixed Price				Weighted Average Short Put Price			Weighted Average Floor Price			Weighted Average Ceiling Price
2020	Sold Calls	NYMEX WTI	8,000		$	—		$	65.59			$	—		$	—		$	—
2020	Swaps	NYMEX WTI	35,000		—			58.12				—			—			—
2020	Three-Way Collars	NYMEX WTI	30,000		—			—				48.33			57.87			64.27
Jan2020-Jun2020	Swaps	NYMEX WTI	24,000		—			59.54				—			—			—
Jul2020-Dec2020	Call Swaption	NYMEX WTI	11,000		—			58.95				—			—			—
2020	Basis Swaps	(1)	15,000		(5.01		)	—				—			—			—

(1)	We have entered into crude oil basis swap contracts in order to establish a fixed amount for 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.

As of December 31, 2019, we had entered into the following NGL derivative instruments:

					Swaps
Settlement Period	Type of Contract	Index	Bbls per Day		Weighted Average Fixed Price
Apr 2020-Sept 2020	Ethane Swaps	Mont Belvieu	2,000		$	7.77
Apr 2020-Sept 2020	Propane Swaps	Mont Belvieu	5,000		21.04
Apr 2020-Sept 2020	Isobutane Swaps	Mont Belvieu	1,000		25.36
Apr 2020-Sept 2020	Butane Swaps	Mont Belvieu	1,500		24.31

As of December 31, 2019, we had entered into the following natural gas derivative instruments:

						Swaps							Collars
Settlement Period	Type of Contract	Index	MMBtu per Day			Weighted Average Differential			Weighted Average Fixed Price				Weighted Average Short Put Price			Weighted Average Floor Price			Weighted Average Ceiling Price
Apr2020-Dec2020	Swaps	NYMEX HH	90,000			$	—		$	2.60			$	—		$	—		$	—
Apr2020-Oct2020	Three-Way Collars	NYMEX HH	40,000			—			—				2.25			2.70			2.85
2020	Sold Puts	NYMEX HH	90,000			—			—				2.15			—			—
2020	Basis Swaps	CIG (1)	139,000			(0.56		)	—				—			—			—
2020	Basis Swaps	Waha (1)	49,500			(1.05		)	—				—			—			—
2021	Basis Swaps	CIG (1)	60,000			(0.52		)	—				—			—			—
2021	Basis Swaps	Waha (1)	14,000			(0.60		)	—				—			—			—

(1)	We have entered into natural gas basis swap contracts in order to establish a fixed amount for the differential between index pricing for Colorado Interstate Gas (CIG) and Waha Hub versus NYMEX Henry Hub (HH). The weighted average differential represents the amount of reduction to NYMEX HH prices for the notional volumes covered by the basis swap contracts.

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Fair Value Amounts and Gains and Losses on Derivative Instruments   The fair values of derivative instruments on our consolidated balance sheets were as follows (in millions): 

Asset Derivative Instruments									Liability Derivative Instruments
Balance Sheet Location	December 31, 2019				December 31, 2018				Balance Sheet Location	December 31, 2019				December 31, 2018
Other Current Assets	$	14			$	180			Other Current Liabilities	$	36			$	1
Other Noncurrent Assets	1				—				Other Noncurrent Liabilities	1				26
Total Assets	$	15			$	180			Total Liabilities	$	37			$	27

We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published London Inter-bank Offered Rate (LIBOR) rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which considers market volatility, market prices and contract terms. Amounts include the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.

The effect of derivative instruments on our consolidated statements of operations was as follows:

	Year Ended December 31,
(millions)	2019				2018				2017
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
Crude Oil	$	(10	)		$	162			$	(14	)
Natural Gas	(22		)		(1		)		1
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments	(32		)		161				(13		)
Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments
Crude Oil	184				(225		)		18
NGLs	(3		)		—				—
Natural Gas	(6		)		1				(68		)
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments	175				(224		)		(50		)
Loss (Gain) on Commodity Derivative Instruments
Crude Oil	174				(63		)		4
NGLs	(3		)		—				—
Natural Gas	(28		)		—				(67		)
Total Loss (Gain) on Commodity Derivative Instruments	$	143			$	(63	)		$	(63	)

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Note 15. Additional Shareholders’ Equity Information

Common Stock and Treasury Stock Activity in shares of our common stock and treasury stock was as follows:

	Year Ended December 31,
	2019			2018
Shares of Common Stock Issued
Shares, Beginning of Period	521,055,001			528,743,381
Exercise of Common Stock Options	—			576,617
Restricted Stock Awarded, Net of Forfeitures	2,768,731			2,488,363
Purchase and Retirement of Common Stock (1)	—			(10,008,128	)
Adjustment to Shares Exchanged in Clayton Williams Energy Acquisition	—			(745,232	)
Shares, End of Period	523,823,732			521,055,001
Treasury Stock
Shares, Beginning of Period	38,851,988			38,786,969
Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock	240,865			267,258
Rabbi Trust Shares Distributed and/or Sold	(203,063	)		(202,239	)
Shares, End of Period	38,889,790			38,851,988
Additional Information
Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust	—			—
Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Earnings (Loss) per Share (2)	13,892,742			15,004,591

(1)	On February 15, 2018, we announced that the Company's Board of Directors had authorized a share repurchase program of $750 million which expires December 31, 2020. In 2019, no shares were repurchased and retired. In 2018, shares were repurchased and retired at an average price of $29.49 per share.

(2)	For the years ended December 31, 2019 and 2018, 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.

Accumulated Other Comprehensive Loss (AOCL) AOCL in the shareholders’ equity section of the balance sheet included:

(millions)	Interest Rate Cash Flow Hedge				Other Postretirement Benefit Plans				Total
December 31, 2016	$	(21	)		$	(10	)		$	(31	)
Realized Amounts Reclassified Into Earnings	1				4				5
Unrealized Change in Fair Value	—				(4		)		(4		)
December 31, 2017	(20		)		(10		)		(30		)
Realized Amounts Reclassified Into Earnings	(3		)		1				(2		)
December 31, 2018	(23		)		(9		)		(32		)
Realized Amounts Reclassified Into Earnings	1				—				1
December 31, 2019	$	(22	)		$	(9	)		$	(31	)

Items in AOCL were initially recorded net of tax, using an effective income tax rate of 35%. In fourth quarter 2018, we reclassified to retained earnings approximately $6 million representing the effect of the decrease in the income tax rate to 21%.

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Note 16. Stock-Based and Other Compensation Plans

We recognized total stock-based compensation expense as follows:

	Year Ended December 31,
(millions)	2019				2018				2017
General and Administrative Expense	$	59			$	54			$	56
Exploration Expense and Other	9				8				48
Total Stock-Based Compensation Expense (1)	$	68			$	62			$	104
Tax Benefit Recognized	$	(14	)		$	(13	)		$	(36	)

(1)	2019 amount excludes $8 million capitalized to property, plant and equipment.

Stock Option and Restricted Stock Plans   Our stock option and restricted stock plans are described below.

2017 Long-Term Incentive Plan On April 25, 2017, our shareholders approved the Noble Energy, Inc. 2017 Long-Term Incentive Plan (the 2017 Plan). Upon shareholder approval, the 2017 Plan superseded and replaced the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan) which was frozen so that no future grants would be made under the 1992 Plan. The 1992 Plan continues to govern awards that were outstanding as of the date of its suspension, which remain in effect pursuant to their terms. Under the 2017 Plan, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, stock awards and other incentive awards to our officers or other employees and those of our subsidiaries. The maximum number of shares that may be granted under the 2017 Plan is 44 million shares of common stock. At December 31, 2019, 39,693,735 shares of our common stock were reserved for issuance, including 28,407,839 shares available for future grants and awards, under the 2017 Plan.

Stock options are issued with an exercise price equal to the fair market value of our common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire 10 years from the grant date. Option grants generally vest ratably over a three-year period.

Restricted stock awards made under the 2017 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. During the period in which such restrictions apply, unless specifically provided otherwise in accordance with the terms of the 2017 Plan, the recipient of restricted stock would be the record owner of the shares and have all the rights of a shareholder with respect to the shares, including the right to vote and the right to receive dividends or other distributions made or paid with respect to the shares. The dividends or other distributions pertaining to the restricted shares will be held by the Company until the restriction period ends and the shares vest or forfeit. If the restricted shares forfeit, then the recipient shall not be entitled to receive the dividend or distribution, which will transfer to the Company. Restricted stock awards with a time-vested restriction vest over a two or three-year period. Performance share awards cliff vest after a three-year period if the Company achieves certain levels of total shareholder return relative to a pre-determined industry peer group.

2015 Stock Plan for Non-Employee Directors   The 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as amended (the 2015 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2015 Plan superseded and replaced the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. The total number of shares of our common stock that may be issued under the 2015 Plan is 708,996. At December 31, 2019, 485,062 shares of our common stock were reserved for issuance, including 306,243 shares available for future grants and awards, under the 2015 Plan.

Stock Option Grants   The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below:

•

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   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.

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•	Risk-free rate  Represents 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  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.

The assumptions used in valuing stock options granted were as follows:

	Year Ended December 31,
(weighted averages)	2019				2018				2017
Expected Term (in Years)	6.9				6.7				6.4
Expected Volatility	33.8		%		33.4		%		33.2		%
Risk-Free Rate	2.7		%		2.6		%		2.2		%
Expected Dividend Yield	1.4		%		1.2		%		0.9		%
Weighted Average Grant-Date Fair Value	$	7.57			$	10.47			$	13.26

Stock option activity was as follows:

	Options			Weighted Average Exercise Price				Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
				(per share)				(years)		(millions)
Outstanding at December 31, 2018	13,852,020			$	44.04
Granted	461,311			22.15
Forfeited	(51,100	)		34.72
Expired	(1,686,478	)		35.26
Outstanding at December 31, 2019	12,575,753			$	44.62			4.2		$	1
Exercisable at December 31, 2019	11,373,846			$	46.11			3.7		$	—

There were no options exercised in 2019. The total intrinsic value of options exercised was $5 million in 2018 and $4 million in 2017. As of December 31, 2019, $5 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.2 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.

Restricted Stock Awards   Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair value of the market based restricted stock awards was estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three-year period ended prior to the date of award. The risk-free rate is based on a three-year period for US Treasury securities as of the year ended prior to the date of award.

The assumptions used in valuing market based restricted stock awards granted were as follows:

	Year Ended December 31,
	2019			2018			2017
Number of Simulations	10,000,000			10,000,000			500,000
Expected Volatility	37.5	%		35.0	%		35.0	%
Risk-Free Rate	2.5	%		2.3	%		1.5	%

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Restricted stock activity was as follows:

	Subject to Time Vesting							Subject to Market Conditions
	Number of Shares			Weighted Average Award Date Fair Value				Number of Shares			Weighted Average Award Date Fair Value
				(per share)							(per share)
Outstanding at December 31, 2018	3,172,891			$	32.72			1,385,634			$	21.74
Awarded	2,464,682			22.33				1,138,730			13.50
Vested	(906,485	)		34.11				—			—
Forfeited	(486,733	)		27.97				(347,948	)		21.20
Outstanding at December 31, 2019	4,244,355			$	27.02			2,176,416			$	17.52

The total fair value of restricted stock that vested was $20 million in 2019, $29 million in 2018, and $34 million in 2017. The weighted average award-date fair value per share of restricted stock awarded was $19.54 in 2019, $27.96 in 2018, and $35.45 in 2017.

As of December 31, 2019, $74 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.4 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.

Cash-Settled Awards Periodically, we issue cash-settled awards (so called phantom units, the nomenclature used in accounting literature) to certain employees in lieu of a portion of restricted stock and stock options. These phantom units represented a hypothetical interest in the Company and, once vested, are settled in cash. Common stock dividends accrue on phantom units and are paid upon vesting.

On February 1, 2016, we issued one million phantom units under the 1992 Plan, a portion of which were subject to the Company's achievement of certain levels of total shareholder return relative to a pre-determined industry peer group. The phantom units vested during 2019 at $31.65 per share which was equal to the grant date fair value. The fair value of the market based phantom unit awards was estimated on the date of award using a Monte Carlo valuation model and assumed 500,000 simulations, 38% expected volatility and a risk-free rate of 0.9%. These awards vested at 0% as performance was not achieved.

On February 19, 2019, we issued 803,606 phantom units under the 2017 Plan. The units had a grant date fair value of $22.39 and vest ratably over three years. The value at vesting will equal the fair market value of a share of common stock of the Company as of the vesting date.

Phantom unit activity was as follows:

	Subject to Time Vesting							Subject to Market Conditions
	Number of Units			Weighted Average Award Date Fair Value				Number of Units			Weighted Average Award Date Fair Value
				(per share)							(per share)
Outstanding at December 31, 2018	467,365			$	31.65			150,296			$	6.82
Awarded	803,606			22.39				—			—
Vested	(462,823	)		31.65				—			—
Forfeited	(92,762	)		22.55				(150,296	)		6.82
Outstanding at December 31, 2019	715,386			$	22.39			—			$	—

As of December 31, 2019, $11 million of compensation cost related to phantom units remained to be recognized. The cost is expected to be recognized over a weighted-average period of 2.1 years. The total fair value of phantom units that vested in 2019 was $10 million. We accrued a liability of $5 million in 2019 related to the phantom units.

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Other Compensation Plans

401(k) Plan   We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $32 million in 2019, $31 million in 2018 and $31 million in 2017.

Deferred Compensation Plans We have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants may elect to receive distributions in either cash or shares of our common stock. Assets within the rabbi trust primarily consist of mutual fund investments, which include various publicly-traded mutual funds that, in turn, include investments ranging from equities to money market instruments and totaled $27 million at December 31, 2019. The fair values are based on quoted market prices for identical assets.

The liability associated with the deferred compensation plan, which is dependent upon the fair values of the mutual fund investments and common stock held in the rabbi trust, was $29 million and $43 million at December 31, 2019 and 2018, respectively. The rabbi trust included 64,729 and 267,792 shares of our common stock at December 31, 2019 and 2018, respectively, which are accounted for as treasury stock. Distributions of 200,000 shares were made in each of 2019, 2018 and 2017 and were valued at $23 million in 2019, $18 million in 2018 and $21 million in 2017.

All fluctuations in market value of the deferred compensation liability have been reflected in other non-operating (income)

expense, net in the consolidated statements of operations. We recognized deferred compensation expense of $9 million in 2019, $2 million in 2018 and $9 million in 2017.

We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities under these plans were $99 million and $104 million at December 31, 2019 and 2018, respectively.

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•	2017 revisions were primarily attributable to the Delaware Basin due to continued optimization of well development and improved producing well performance.

•	2018 revisions included 30 MMBbls for changes in expected recoveries and increased operating and capital costs in the Delaware Basin and 11 MMBbls for changes in the previously adopted development plans in the Eagle Ford Shale and DJ Basin.

•	2019 revisions included a 41 MMBbls revision (29 MMBbls of PUDs and 12 MMBbls of proved developed) in the Delaware Basin for changes in development plans and performance.

•	2017 included additions of 59 MMBbls and 42 MMBbls in the Delaware and DJ Basins, respectively, primarily due to the addition of planned new locations and activity.

•	2018 extensions relate to drilling plans for new wells and primarily include 55 MMBbls and 38 MMBbls in the Delaware and DJ Basins, respectively.

•	2019 additions of 52 MMBbls and 22 MMBbls in the DJ Basin and Delaware Basin, respectively, related to drilling plans for new wells.

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•	2017 sales included Marcellus Shale upstream assets and other non-strategic US onshore assets.

•	2018 sales included 16 MMBbls related to our Gulf of Mexico assets and 8 MMBbls related to other non-strategic US onshore assets.

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•	2017 US revisions included 11 MMBbls in the Delaware Basin, 8 MMBbls in the Eagle Ford Shale and 6 MMBbls in the DJ Basin, due to continued optimization of well development and improved producing well performance.

•	2018 revisions included positive revisions of 35 MMBbls in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 19 MMBbls, primarily in the Eagle Ford Shale due to changes in the previously adopted development plan.

•	2017 extensions in US reserves included 19 MMBbls in the DJ Basin, 9 MMBbls in the Delaware Basin and 4 MMBbls in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.

•	2018 extensions related to the addition of planned new locations and activity, of which 25 MMBbls, 15 MMBbls and 8 MMBbls related to the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively.

•	2019 extensions included additions of 40 MMBbls in the DJ Basin due to drilling plans for new wells.

•	2017 sales included the Marcellus Shale upstream assets and other non-strategic US onshore assets.

•	2018 sales included 1 MMBbl from Gulf of Mexico assets and 6 MMBbls for certain non-core US onshore assets.

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•	2017 US revisions included 81 Bcf in the Eagle Ford Shale and 31 Bcf in the Delaware Basin, partially offset by negative performance revisions of 49 Bcf in the DJ Basin primarily associated vertical well locations. The Israel revision was associated with the integration of the Tamar 8 well results in our geologic modeling across the reservoir.

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2018 US revisions included positive revisions of 70 Bcf in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 71 Bcf in the Eagle Ford Shale due to changes in the previously adopted development plan and 42 Bcf primarily in the Delaware Basin due to changes in expected recoveries and increased operating and capital costs. Additional reserves of 17 Bcf in Equatorial Guinea and 2 Bcf in Israel relate to improved recoveries on existing wells.

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2019 revisions in US onshore included a 41 Bcf negative revision in the Eagle Ford Shale due to performance, partially offset by positive revisions due to performance in the DJ Basin. In Israel, revisions to our Tamar field included positive revisions to developed reserves of 460 Bcf, partially offset by revisions to PUD reserves of 241 Bcf. The Tamar field PUDs were reclassified to developed reserves based on our determination the reserves are accessible with limited further development. Equatorial Guinea revisions relate to the sanction of the Alen Gas Monetization project, which extends the life of the Alba field as certain natural gas volumes are now economic to produce.

•	2017 extensions in US reserves included additions of 224 Bcf in the DJ Basin, 53 Bcf in the Delaware Basin and 22 Bcf in

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•	2018 extensions related to drilling plans for new wells. Increases in the US included 254 Bcf, 77 Bcf and 42 Bcf in the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively, and the increase in Israel of 68 Bcf related to the Tamar field.

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2019 extensions in US onshore included additions of 345 Bcf in the DJ Basin due to drilling plans for new wells. Israel additions relate to the Leviathan field and are due to closing of the EMG Pipeline transaction and signing of amendments to our natural gas sales agreements with Egyptian customers, which significantly increase our firm sales commitments in the region. Additions in Equatorial Guinea relate to sanction of the Alen Gas Monetization project in second quarter 2019.

•	2017 sales included our Marcellus Shale upstream assets and other non-strategic US onshore assets.

•	2018 sales included 20 Bcf for our Gulf of Mexico assets, 59 Bcf for other non-strategic US onshore assets and 502 Bcf for a 7.5% working interest in the Tamar field, offshore Israel.

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

(2)	Amount for Israel includes $100 million for the write-off of the Leviathan Deep prospect.

(3)	See Note 10. Impairments.

(4)

Income tax (benefit) expense is based upon respective corporate statutory tax rates. During all periods presented, we incurred exploration expense in currently non-commercial other international locations; therefore, no tax benefit was included in income tax expense for 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 activities, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements, and overhead and interest costs.

(6)	See Note 4. Acquisitions and Divestitures.

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(1)	2019 and 2018 unproved property acquisition costs include US onshore undeveloped leasehold activity during the year.

(2)	2019 and 2018 exploration costs primarily relate to lease rentals, seismic and staffing expense. 2019 costs exclude $100 million of dry hole expense related to the Leviathan Deep prospect as the associated unproved capital costs were incurred in prior years.

(3)

2019 costs to develop our PUDs totaled $1.5 billion. Of this amount, $1.1 billion, $399 million and $48 million related to the conversion of year end 2018 PUDs to proved developed reserves in US onshore, the Leviathan field and the Aseng crude oil well, respectively. In addition, we spent $131 million to convert unproved reserves to proved developed reserves in US onshore and $24 million progressing PUDs that have not yet been converted to proved developed reserves. Development costs also included a decrease of $9 million in ARO, consisting of downward revisions of $57 million in US onshore partially offset by additions of $40 million in Israel related to Leviathan.

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

(2)	At December 31, 2019, includes asset retirement costs of $954 million and assets held for sale of $14 million.

(1)	During 2018, we reduced our ownership in the Tamar field, offshore Israel, to 25% through the sale of a 7.5% interest. Amounts at December 31, 2019 and December 31, 2018 reflect a 25% interest while amounts at December 31, 2017 reflect a 32.5% working interest. See Note 4. Acquisitions and Divestitures. In 2017, we sanctioned the first phase of development of the Leviathan field.

(2)	Other International represents changes in North Sea abandonment costs.

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(3)	Excludes 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 7. 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. Future income tax expense for Israel includes the effect of estimated future profit levy taxes and changes to corporate income tax rates.

(1)	Natural gas from the Alba field is sold for $0.25 per MMBtu and is adjusted for energy content. In 2019, we recorded natural gas PUDs associated with the Alen Gas Monetization project with future cash inflows from LNG sales estimated based upon pricing linked principally to the ICE Brent index.

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(1)	The decrease in 2019 and increases in 2018 and 2017 were driven primarily by 12-month average commodity prices.

(2)	The decrease in 2019 relates to primarily to capital efficiencies in our US onshore program and changes in development plans in the Delaware Basin.

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

(4)	See Note 4. Acquisitions and Divestitures.

(5)	2019 increase in future income tax expense relates primarily to higher future cash flows from the Leviathan and Tamar fields and from cash flows attributable to Alen Gas Monetization, partially offset by a decrease in US income tax expense due to lower future taxable income.

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•	Proved property impairment charge of $1.2 billion in the Eagle Ford Shale. See Note 10. Impairments; and

•	$100 million dry hole cost. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

•	$572 million pre-tax gain on divestitures. See Note 4. Acquisitions and Divestitures;

•	$168 million impairment expense related to Gulf of Mexico asset divestiture. See Note 4. Acquisitions and Divestitures; and

•	$145 million discrete tax benefit, net, related to changes in federal income tax regulations. See Note 13. Income Taxes.

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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.

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(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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