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(1)	Final investment decision has been made.

(2)	Represents multiple ongoing development projects.

(3)	See Update on Core Area – Israel, below.

(4)	Regulatory approval for the project has been delayed. We recently petitioned the Israeli courts to expedite approval.

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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 natural gas is significantly less than the price for a barrel of crude oil. The price for a barrel of NGL is also less than the price for a barrel of crude oil. See Item 6. Selected Financial Data.

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•	Changes in Tax Law   In March 2011, the Israeli government enacted the Oil Profits Taxation Law, 2011 (Petroleum Profits Law), which imposed additional income tax on crude oil and natural gas production. The Israeli government also repealed the percentage depletion deduction and made certain changes to the rules for deducting tangible and intangible development costs.

•

Natural Gas Policy In September 2012, the Interministerial Committee to Examine Government Policy Regarding the Natural Gas Industry in Israel (the Interministerial Committee) issued final recommendations regarding a government policy for developing Israel’s natural gas economy. The recommendations included, among others, material restrictions on our ability to monetize our natural gas discoveries. The recommendations approved by the Israeli government included further limitations on exports of natural gas than were recommended by said committee. See Regulations – Israel’s Natural Gas Policy, below.

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Israel Antitrust Authority The Israeli Antitrust Commissioner (Commissioner) has intervened regarding the terms used in long-term contracts with certain natural gas customers; contended that the original acquisition agreement for the Leviathan acreage is an illegal restrictive arrangement; and, most recently, reversed a decision to submit a previously-agreed consent decree on certain antitrust matters (Consent Decree) to the Israeli Antitrust Tribunal for approval. Acting in good faith upon the Consent Decree, we consented to divest our Tanin and Karish natural gas discoveries and have been in discussions with potential purchasers. We believed that the Consent Decree matter had been resolved some time ago and had received recent assurances from the Antitrust Authority that approval was forthcoming. However, on December 23, 2014, we and our partners in the Leviathan field were advised by the Israel Antitrust Authority of its decision to not submit the Consent Decree to the Antitrust Tribunal for final approval. We requested an oral hearing with the Antitrust Authority, which took place on January 27, 2015, and await final disposition. See Regulations – Israel Antitrust Authority, below.

•	Delay in Development Plan Approval We have worked with the Israeli government for some time to obtain regulatory approval for the Tamar Southwest development plan, and recently petitioned the Israeli courts to expedite the needed approvals.

•	Pricing Disputes The Public Utility Authority (PUA) has amended its own pricing formulas to impact pricing of natural gas in the Israeli market. These actions created pricing disputes between natural gas sellers and buyers. In addition, there have been threats of price controls.

•	Maritime Zones Law Bill The Israeli government has advanced a Maritime Zones Law bill that may adversely impact the ability to conduct oil and gas exploration and production activities in our offshore leases and licenses.

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•	Approval of final GSPAs with off-takers, to support financing arrangements;

•	Clear, economically viable tax rulings, including export tax rulings;

•	Export approval with reasonable export allocations;

•	Approvals of Plans of Development;

•	Acceptable resolution of Leviathan and other pending matters with the Israeli Antitrust Authority;

•	Timely permitting;

•	Prompt decisions regarding pipeline onshore landing sites;

•	Stability clauses and protection from changes in laws and regulations;

•	Stable fiscal and contract terms that allow for financial returns that are appropriate to support long-term investment by a global exploration and production company; and

•	Other relevant regulatory terms essential to offshore crude oil and natural gas exploration and production.

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

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

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

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

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•	183 MMBoe in the DJ Basin. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling activity, we expect these PUDs to be converted to proved developed reserves within a five-year period;

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•	179 MMBoe in the Marcellus Shale. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling activity, we expect these PUDs to be converted to proved developed reserves within a five-year period;

•	28 MMBoe in the deepwater Gulf of Mexico;

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59 MMBoe in the Alba field, offshore Equatorial Guinea, 57 MMBoe of which have been recorded as PUDs for over five years and are attributable to a sanctioned compression project which is currently under construction and expected to come online mid-2016. These volumes, which will be recovered through existing wells, will be reclassified to proved developed at start-up, currently expected in 2016; and

•	74 MMBoe in Israel primarily in the Tamar and Tamar Southwest fields. PUDS of 32 MMBoe relate to the Tamar Southwest field, which is awaiting government approval of the development plan.

•	downward revisions of 14 MMBoe, primarily due to planned reduction in pace of DJ Basin drilling activity due to lower commodity price outlook;

•	additions of 26 MMBoe in the DJ Basin horizontal drilling program; 59 MMBoe in the Marcellus Shale horizontal drilling program; and 10 MMBoe in the Gulf of Mexico; and

•	conversion of 115 MMBoe into proved developed reserves attributable to ongoing development in the DJ Basin (24% of year end 2013 PUD volumes converted) and Marcellus Shale (34% of year end 2013 PUD volumes converted).

•	positive revisions of 1 MMBoe due to performance revisions for the Alba field.

•	positive revisions of 2 MMBoe due to performance revisions for the Tamar field.

•	sales of 2 MMBoe due to the sale of our China assets in June 2014.

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

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

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

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

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(2)

Natural gas from the Alba field is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. Sales to these plants are based on a Btu equivalent and then converted to a dry gas equivalent volume. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting. The volumes produced by the LPG plant are included in the crude oil information.

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

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(1)	Represents acreage that will expire if no further action is taken to extend. Approximately 91% of the acreage is located in core areas where we currently expect to continue development activities and/or extend the lease terms.

(2)	Represents acreage that will expire if no further action is taken to extend. We currently intend to extend the leases prior to expiration in accordance with license terms. See also Regulations – Israel Natural Gas Policy and Israel Antitrust Authority, below.

(3)	Represents acreage that will expire if no further action is taken to extend. The acreage represents the Tilapia PSC. We intend to formally request an extension of the lease during first quarter 2015; however, the extension timeline could vary and it is therefore unknown what percentage of acreage will be relinquished in 2015.

(4)	Represents acreage that we expect to relinquish to the Nicaraguan government in the first half of 2015.

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

(2)	Includes wells pending completion activities.

(3)	Includes the Tanin and Karish exploratory wells which have been classified as assets held for sale as of December 31, 2014.

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

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

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

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

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

•	the Petroleum Directorate which regulates our exploration activities offshore Sierra Leone; and

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

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

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

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

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

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

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

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

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

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

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

•	disclose chemicals they inject by using an online database, with an exception for chemicals deemed to be trade secrets;

•	verify that wells are drilled properly so that toxic fluids do not contaminate groundwater; and

•	submit plans for managing drilling wastewater in lined pits or storage tanks.

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

•	Item 1A. Risk Factors; and

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

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•	economic factors impacting global gross domestic product growth rates;

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

•	global factors impacting supply quantities of crude oil, natural gas and NGLs, in particular, US crude oil and NGL supply growth resulting from shale oil development;

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

•	the extent to which US shale producers become swing producers, yielding additional non-OPEC crude oil supply;

•	further application of horizontal drilling techniques which could increase production and significantly impact both domestic and global supplies of crude oil, natural gas, and NGLs;

•	our ability to develop natural gas in shale or crude oil in tight formations relatively inexpensively which could increase the supply of natural gas or crude oil;

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

•	actions taken by foreign hydrocarbon-producing nations;

•	political conditions and events (including instability or armed conflict) in hydrocarbon-producing regions;

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

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

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

•	the availability of pipeline capacity and infrastructure;

•	the availability of crude oil transportation and refining capacity;

•	weather conditions;

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

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

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

•	domestic and foreign governmental regulations and taxes.

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

•	curtailment or shut-in of our production due to lack of transportation or storage capacity;

•	reduction in the amount of crude oil, natural gas and NGLs that we can produce economically;

•	certain properties in our portfolio becoming economically unviable;

•	delay or postponement of some of our capital projects;

•	further reduction of our 2015 capital investment program, or significant reductions in future capital investment programs, resulting in a reduced ability to develop our reserves;

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

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

•	declines in our stock price.

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

•	additional counterparty credit risk exposure on commodity hedges; and

•	reduction in the carrying value of goodwill.

•	the current low commodity price environment;

•	lack of government approval for projects, including Israeli government approval for Leviathan Phase 1 development;

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

•	significant delays in delivery of essential items or performance of services, cost overruns, supplier insolvency, or other critical supply failure which could adversely affect project development;

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

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•	drilling hazards or accidents or natural disasters.

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

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

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

•	changes in drilling or safety regulations in other countries as a result of the Deepwater Horizon Incident, a large oil spill occurring in the Gulf of Mexico in 2010, or other incidents that have occurred;

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

•	foreign exchange restrictions;

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

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

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•	restrict resource access or investment in lease holdings;

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

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

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

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

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

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

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

•	adversely affect the price of our common stock.

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

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

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

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

•	disruption of our operations due to evacuation of personnel;

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

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

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

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

•	inability of our service and equipment providers to deliver items necessary for us to conduct our operations resulting in a halt or delay in our planned exploration activities, delayed development of major projects, or shut-in of producing fields;

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

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

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

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•	injuries and/or deaths of employees, supplier personnel or other individuals;

•	pipeline ruptures and spills;

•	fires, explosions, blowouts and well cratering;

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

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

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

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

•	release of pollutants;

•	surface spillage of, or contamination of groundwater by, fluids used in operations;

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

•	theft or vandalism of oilfield equipment and supplies, especially in areas of active onshore operations;

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

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

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

•	volcanoes which could affect our operations offshore Equatorial Guinea;

•	flooding which could affect our operations in low-lying areas;

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

•	other natural disasters; and

•	pandemics and epidemics, such as the Ebola virus, which is ongoing in certain regions of West Africa and may adversely affect our business operations through travel or other restrictions.

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

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

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

•	downgrades in credit rating or liquidity problems;

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

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

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•	blocked development;

•	denial or delay of drilling permits;

•	shortening of lease terms or reduction in lease size;

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

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

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

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

•	legal challenges or lawsuits;

•	increased regulation of our business;

•	damaging publicity about the Company;

•	increased costs of doing business;

•	reduction in demand for our products; and

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

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

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

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

•	a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt one of our major development projects, effectively delaying the start of cash flows from the project;

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

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

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

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

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

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

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

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

•	landowner and/or foreign governments' opposition to infrastructure development;

•	regulation of federal land by the BLM;

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

•	disputes regarding leases; and

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

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

•	exploration activities on federal lands in northeast Nevada subject us to additional regulatory requirements as compared with such activities conducted on private land;

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

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

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

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

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

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

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

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

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

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•	large multi-national, integrated oil companies;

•	state-controlled national oil companies;

•	US independent oil and gas companies;

•	service companies engaging in exploration and production activities; and

•	private oil and gas equity funds.

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

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

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

•	attracting and retaining employees with certain skills.

•	lower commodity price outlook;

•	title problems;

•	near-term lease expiration;

•	decisions impacting allocation of capital;

•	compliance with environmental and other governmental requirements;

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

•	unexpected drilling conditions;

•	pressure or other irregularities in formations;

•	equipment failures or accidents; and

•	adverse weather conditions.

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

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

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

•	anticipated development cycle time;

•	future development costs;

•	future operating costs;

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

•	severance and excise taxes; and

•	workover and remedial costs.

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•	increase the costs of drilling exploratory and development wells;

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

•	result in additional operating costs;

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

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

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

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

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•	our growth strategies;

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

•	anticipated trends in our business;

•	our future results of operations;

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

•	market conditions in the oil and gas industry;

•	our ability to make and integrate acquisitions;

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

•	access to resources.

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

(2)	Prices for 2010 include effects of crude oil and natural gas cash flow hedging activities.

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•	Executive Overview;

•	Operating Outlook;

•	Results of Operations;

•	Proved Reserves;

•	Liquidity and Capital Resources; and

•	Critical Accounting Policies and Estimates.

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

•	we have positive operating cash flow (revenues less cash operating expenses), prior to capital expenditures, in each of our core areas;

•	we have designed a substantially-reduced capital investment program which will allow us to respond to conditions that occur in 2015;

•	we are well hedged, with approximately 60% of global crude oil and 50% of domestic natural gas production hedged for 2015, with additional quantities hedged into 2016;

•	we have a strong balance sheet; and

•	we have robust liquidity.

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•	net income of $1.2 billion (all from continuing operations), as compared with $978 million (including $907 million from continuing operations) for 2013;

•	gain on divestitures of $73 million, as compared with $36 million for 2013;

•	dry hole expense of $226 million, as compared with $149 million for 2013;

•	asset impairment charges of $500 million, as compared with $86 million for 2013;

•	gain on commodity derivative instruments of $976 million (including $947 million non-cash portion), as compared with $133 million loss on commodity derivative instruments (including $131 million non-cash portion) for 2013;

•	diluted earnings per share of $3.27, as compared with $2.69 for 2013;

•	cash flows provided by operating activities of $3.5 billion, as compared with $2.9 billion in 2013; and

•	capital spending of $5.0 billion, as compared with $4.4 billion in 2013.

•	proceeds of $321 million from sales of non-core properties;

•	cash distributions of $204 million from CONE Gathering subsequent to the formation of a master limited partnership for Marcellus Shale midstream assets and completion of the initial public offering; and

•	issuance of $1.5 billion unsecured notes at Company-record low coupon levels.

•	ending cash and cash equivalents balance of approximately $1.2 billion at December 31, 2014, as compared with $1.1 billion at December 31, 2013;

•	total liquidity of $5.2 billion at December 31, 2014 (consisting of year-end cash balance plus funds available under our Credit Facility) as compared with $5.1 billion at December 31, 2013; and

•	year-end ratio of debt-to-book capital of 38%, as compared with 35% at December 31, 2013.

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

•	the level of horizontal drilling activity in the DJ Basin and the Marcellus Shale;

•	decline in DJ Basin legacy vertical well production and capacity constraints of midstream facilities serving those wells;

•	timing of start-up of the Big Bend project (deepwater Gulf of Mexico);

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

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

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

•	potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico, or winter storms and flooding in the DJ Basin and/or Marcellus Shale;

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

•	pending Alba and Alen field unitizations in West Africa;

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

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

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

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

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

•	permitting activity in the deepwater Gulf of Mexico;

•	drilling results;

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

•	property acquisitions and divestitures;

•	exploration activity offshore Cameroon and the Falkland Islands;

•	cash flows from operations;

•	indebtedness levels;

•	availability of financing or other sources of funding;

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

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

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

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(1)

Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for natural gas is significantly less than the price for a barrel of crude oil. The price for a barrel of NGL is also less than the price for a barrel of crude oil.

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

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

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

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

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

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

•	higher sales volumes of 14 MBoe/d in the DJ Basin attributable to the acceleration of our horizontal drilling program;

•	the addition of sales volumes from Alen, offshore Equatorial Guinea, which began producing in late second quarter 2013; and

•	higher production at Galapagos due to continued strong performance and a full year online;

•	reduction in sales volumes due to the sales of non-core, onshore US properties during 2013;

•	a 1% decrease in total consolidated average realized prices primarily due to increased supply;

•	a volume reduction in West Africa due to natural field decline at Aseng; and

•	natural field decline in non-core onshore US and deepwater Gulf of Mexico areas.

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

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

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

•	partially offset by:

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

•	increases in total consolidated average realized prices primarily due to increased demand from expectations of cooler weather and higher-than-expected inventory withdrawals;

•	higher sales volumes in Israel from Tamar, which began production at the end of first quarter 2013 and contributed 153 MMcf/d during 2013; and

•	higher sales volumes in the DJ Basin (15 MMcf/d) and Marcellus Shale (49 MMcf/d) in 2013 primarily attributable to our horizontal drilling programs;

•	lower sales volumes due to our non-core onshore US divestiture program; and

•	lower sales volumes due to natural field decline from Mari-B, Noa and Pinnacles, offshore Israel, which contributed a combined 56 MMcf/d during 2013, compared with 101 MMcf/d during 2012.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•	increases of $46 million in the DJ Basin and $4 million in the Marcellus Shale due to new wells coming on line and increased production;

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•	an increase of $58 million in the deepwater Gulf of Mexico due to a full year of production at Galapagos, mechanical repairs at Swordfish, and other repair and maintenance expense;

•	operating expenses of $24 million related to the Tamar field, offshore Israel, which began producing at the end of first quarter 2013; and

•	operating expenses of $18 million related to the Alen field, offshore Equatorial Guinea, which began producing at the end of second quarter 2013;

•	a reduction of $52 million related to the sale of non-core onshore US properties in 2012 and 2013.

(1)	West Africa includes Equatorial Guinea, Cameroon, Sierra Leone, Gabon, and Senegal/Guinea-Bissau, which we exited in 2012.

(2)	Eastern Mediterranean includes Israel and Cyprus.

(3)	Other International includes various international new ventures such as offshore Nicaragua, which we are currently exiting, and offshore Falkland Islands.

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

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

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

•	Other Int'l dry hole cost related to the Paraiso exploratory well (offshore Nicaragua), which did not find commercial quantities of hydrocarbons;

•	seismic expense related to the Gulf of Mexico lease sale and exploration programs offshore Cyprus and offshore Falkland Islands; and

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

(1)	DD&A expense includes accretion of discount on asset retirement obligations of $36 million in 2014, $26 million in 2013, and $22 million in 2012.

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

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

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

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

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

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

•	increase of $16 million associated with corporate assets;

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

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

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

•	higher sales volumes due to increased development activity in the DJ Basin and Marcellus Shale accounted for increases of $218 million and $34 million, respectively;

•	higher production at Galapagos and a new well at Ticonderoga, deepwater Gulf of Mexico, resulted in additional DD&A expense of approximately $48 million;

•	the start up of Alen, offshore Equatorial Guinea, resulted in additional DD&A expense of $44 million; and

•	the start up of Tamar, offshore Israel, resulted in additional DD&A expense of $40 million;

•	partially offset by:

•	a decrease of approximately $53 million onshore US, primarily due to the impact of sales of non-core properties during 2012 and 2013;

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•	a decrease of $52 million in the deepwater Gulf of Mexico due to maintenance and repair downtime and declining production at older fields;

•	a decrease of $40 million at the Aseng field, offshore Equatorial Guinea, due to natural field decline and timing of liftings; and

•	a decrease of $54 million at the Mari-B/Noa/Pinnacles fields, offshore Israel, due to natural field decline and decreased book value from previous impairments.

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

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

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(1)	Includes exploration expense of $27 million in 2012 related to the Selkirk field, which we determined was uneconomic for joint development.

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

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

•

changes for the year ended December 31, 2012 included a negative revision of 94 MMBoe due to our decision to terminate the legacy vertical drilling program in the DJ Basin and focus on horizontal development; net positive revisions of 23 MMBoe, primarily related to better than expected well performance in the Marcellus Shale, the deepwater Gulf of Mexico, and the Aseng field; and negative revisions of 26 MMBoe due to changes in commodity prices.

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

•

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

•	changes for the year ended December 31, 2012 included an increase of 149 MMBoe in the DJ Basin as a result of our decision to focus capital and resources on horizontal development of the Niobrara formation, 56 MMBoe related to ongoing development of the Marcellus Shale, 7 MMBoe related to the ongoing appraisal of the Tamar field, and 6 MMBoe for other projects.

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

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

•	the sale of non-core onshore US and North Sea assets in 2012.

(1)	See Credit Facility, below.

(2)	Total debt includes capital lease and other obligations and excludes unamortized debt discount.

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

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(1)	Unproved property acquisition cost for 2014 includes $68 million in the DJ Basin, $160 million in the Marcellus Shale and $16 million in the deepwater Gulf of Mexico.

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

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

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•	$971 million net increase in debt; and

•	$249 million decrease in shareholders' equity from dividends paid;

•	$1.2 billion increase in shareholders' equity from current year net income.

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(1)	Long-term debt excludes our capital lease and other obligations. See Item 8. Financial Statements and Supplementary Data – Note 9. Long-Term Debt.

(2)	Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2014. See Item 8. Financial Statements and Supplementary Data – Note 9. Long-Term Debt.

(3)	Annual capital lease payments, net to our interest, exclude regular maintenance and operational costs. See Item 8. Financial Statements and Supplementary Data – Note 9. Long-Term Debt.

(4)	Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to procure drilling rigs and other related equipment for exploratory and development drilling activities. See Counterparty Credit Risk, above, and Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.

(5)

Purchase obligations represent our working interest share of contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. See Counterparty Credit Risk, above, and Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.

(6)	Transportation and gathering obligations represent minimum charges for firm transportation and gathering agreements related to our production.  See Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.

(7)	Operating lease obligations represent non-cancelable leases for office buildings and facilities and oil and gas operations equipment used in our daily operations. Amounts have not been discounted. See Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.

(8)	The table excludes deferred compensation liabilities of $218 million and accrued benefit costs of $128 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data – Note 11. Stock-Based and Other Compensation Plans.

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

(10)	There were no open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2014. All our commodity derivative instruments were in a net receivable position at December 31, 2014. See Item 8. Financial Statements and Supplementary Data – Note 7. Derivative Instruments and Hedging Activities.

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

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

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

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

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(1)	Amounts represent increases (decreases) in the fair value of shares of our common stock held in a rabbi trust.

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(1)	The 2014 amount primarily relates to the Dantzler well (deepwater Gulf of Mexico), for which we sanctioned a development plan, and the Tanin and Karish wells (offshore Israel), which were reclassified to assets held for sale. The 2013 amount relates primarily to Gunflint (deepwater Gulf of Mexico), for which we sanctioned a development plan.

(2)	The 2014 amount relates to non-core onshore US exploratory well costs and the Scotia exploratory well (offshore Falkland Islands) which were determined to be non-commercial. The 2012 amount primarily represents deepwater Gulf of Mexico exploratory well costs.

(3)	The 2012 amount relates to North Sea exploratory well costs included in discontinued operations. See Note 3. Property Transactions.

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(1)

In March 2014, we and our partners reached an agreement with the Israel Antitrust Authority on various matters (Consent Decree). The Consent Decree, which was subject to final approval by the Antitrust Tribunal, granted the rights, to us and our partners, to jointly market natural gas from the Leviathan field. Also as a result of the Consent Decree, we agreed to divest our Tanin and Karish natural gas discoveries. However, on December 23, 2014, we and our partners in the Leviathan field were advised by the Israel Antitrust Authority of its decision to not submit the Consent Decree to the Antitrust Tribunal for final approval. This is a matter that we believed was resolved some time ago and we had received recent assurances from the Antitrust Authority that approval was forthcoming. We requested an oral hearing with the Antitrust Authority, which took place on January 27, 2015, and await final disposition.

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

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

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

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

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(1)	We repaid the senior notes on their due date.

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

•

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

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

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

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

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

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

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

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(1)	Excludes capital lease and other obligations. No floating rate debt was outstanding at December 31, 2014 or December 31, 2013. See Note 9. Long-Term Debt.

(1)	Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while our common shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings per share calculations for the year ended December 31, 2014 excludes deferred compensation gains, net of tax.

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(1)	Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 9. Long-Term Debt.

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

(2)	The 2012 US revisions were primarily attributable to our decision to terminate the legacy vertical drilling program in the DJ Basin and focus on the horizontal development of the Niobrara formation. Equatorial Guinea revisions were associated with performance revisions for the Aseng field.

(3)	The 2012 increase in US reserves included an increase of 98 MMBbls in the DJ Basin and 8 MMBbls from Marcellus Shale development. International increases were due primarily to additional development in China.

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(4)	In 2012, we sold non-core, onshore US and North Sea assets.

(5)	Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2014, 2013 and 2012.

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(1)	We are working with the Israeli government to reach agreement on various regulatory matters. See Items 1. and 2. Business and Properties – Update on Core Area – Israel.

(2)	Other International includes China (through June 2014) and the North Sea. See Note 3. Property Transactions.

(3)

The 2012 US revisions were primarily attributable to our decision to terminate the legacy vertical drilling program in the DJ Basin and focus on the horizontal development of the Niobrara formation, and negative price revisions due to lower natural gas prices, partially offset by improved well performance in the Marcellus Shale. Israel revisions were due to performance revisions in the Mari-B field.

(4)	The 2012 increase in US reserves included 305 Bcf in the DJ Basin and 291 Bcf in the Marcellus Shale. The Equatorial Guinea increase was due to additions at Aseng, and the Israel increase was due to additional appraisal activity at Tamar.

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

(6)	In 2012, we sold non-core, onshore US and North Sea assets.

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(1)	The 2012 additions in US reserves included an increase of 5 MMBbls in the DJ Basin and 7 MMBbls from Marcellus Shale development.

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(1)	Other International includes the North Sea, China (through June 30, 2014), Cameroon, Gabon, Sierra Leone, Cyprus, Nicaragua, Falkland Islands, and other new ventures. See Note 3. Property Transactions.

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

(3)	During 2014, 2013 and 2012, we incurred exploration expense in currently non-commercial international locations; therefore, no tax benefit was included in income tax expense associated with Other International as we could not conclude it was more likely than not that some portion or all of the deferred tax assets would be realized.

(4)	Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments, corporate overhead and interest costs. See Note 7. Derivative Instruments and Hedging Activities.

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(1)	Costs incurred include capitalized and expensed items.

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

(3)	2014 unproved property acquisition costs include $68 million and $160 million related to expanding our positions in the DJ Basin and Marcellus Shale, respectively, and $16 million for deepwater Gulf of Mexico lease blocks.

(4)	2014 exploration costs include drilling and completion of $14 million in the DJ Basin, $2 million in the Marcellus Shale, $117 million in the deepwater Gulf of Mexico, $16 million in Equatorial Guinea, $13 million in Israel and $4 million in Cyprus.

(5)	Worldwide development costs include amounts spent to develop PUDs of approximately $2.0 billion in 2014, $1.0 billion in 2013 and $1.8 billion in 2012.

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(1)	Unproved oil and gas properties include amounts remaining from the allocation of costs to unproved properties acquired in previous acquisitions, primarily the Marcellus Shale, of $655 million and $860 million at December 31, 2014 and 2013, respectively.

(2)	Proved oil and gas properties at December 31, 2014 include assets held for sale of $105 million related to non-core onshore US assets and $75 million related to two natural gas discoveries, Tanin and Karish, offshore Israel, and asset retirement costs of $639 million.

(3)	Accumulated DD&A at December 31, 2013 includes $187 million related to China assets held for sale and $50 million related to North Sea assets held for sale. See Note 3. Property Transactions.

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(1)	We are working with the Israeli government to reach agreement on various regulatory matters. See Items 1. and 2. Business and Properties – Update on Core Area – Israel.

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

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

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

(5)	Future development costs include future abandonment costs for each location. Specifically, Other International future development costs as of December 31, 2014 primarily includes the MacCulloch field (North Sea) abandonment costs. See Note 8. Asset Retirement Obligations.

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(1)	Other International includes China (through June 2014) and the North Sea. See Note 3. Property Transactions.

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(1)	First quarter 2014 included the following:

•	$75 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $42 million (See Note 7. Derivative Instruments and Hedging Activities);

•	$1 million pre-tax loss on sale of non-core assets (See Note 3. Property Transactions); and

•	$97 million impairment charges (See Note 4. Asset Impairments).

•	$236 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $187 million (See Note 7. Derivative Instruments and Hedging Activities);

•	$42 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions); and

•	$34 million impairment charges (See Note 4. Asset Impairments).

•	$385 million gain on commodity derivative instruments, including the non-cash portion of the gain on commodity derivative instruments of $397 million (See Note 7. Derivative Instruments and Hedging Activities);

•	$30 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions); and

•	$33 million impairment charges (See Note 4. Asset Impairments).

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•	$903 million gain on commodity derivative instruments, including the non-cash portion of the gain on commodity derivative instruments of $779 million (See Note 7. Derivative Instruments and Hedging Activities);

•	$2 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions); and

•	336 million impairment charges (See Note 4. Asset Impairments).

(2)	First quarter 2013 included the following:

•	$72 million loss on commodity derivative instruments, including non-cash portion of the loss on commodity derivative instruments of $79 million (See Note 7. Derivative Instruments and Hedging Activities); and

•	$12 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions).

•	$161 million gain on commodity derivative instruments, including the non-cash portion of the gain on commodity derivative instruments of $159 million (See Note 7. Derivative Instruments and Hedging Activities).

•	$157 million loss on commodity derivative instruments, including the non-cash portion of the loss on commodity derivative instruments of $147 million (See Note 7. Derivative Instruments and Hedging Activities); and

•	$63 million impairment charges (See Note 4. Asset Impairments).

•	$65 million loss on commodity derivative instruments, including the non-cash portion of loss on commodity derivative instruments of $64 million (See Note 7. Derivative Instruments and Hedging Activities);

•	$24 million pre-tax gain on sale of non-core assets (See Note 3. Property Transactions); and

•	$23 million impairment charges (See Note 4. Asset Impairments).

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

(4)

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

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

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