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•	the DJ Basin (onshore US);

•	the Marcellus Shale (onshore US);

•	the deepwater Gulf of Mexico (offshore US);

•	offshore West Africa; and

•	offshore Eastern Mediterranean.

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•	the majority of our crude oil and natural gas production;

•	visible growth from major development projects; and

•	numerous exploration opportunities.

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(1)	Other international includes the North Sea and China.

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

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•	the Greater Wattenberg Area (GWA), where we have conducted substantial vertical development over the last several years as well as successful horizontal drilling in the high density area and more recently in the less developed northeastern part of GWA. The area is comprised of both an expanding crude oil window to the northeast and strong natural gas window in the core and to the southwest; and

•	northern Colorado from the edge of the GWA to the Wyoming border where we expanded our acreage position and drilled over 25 wells during 2012.

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

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•	$287 million initial cash payment payable at closing;

•	$64 million contingent on the ability to export natural gas; and

•	$113 million contingent on a final investment decision for an LNG project.

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•	a share of Woodside's annual LNG revenue above certain price parameters, subject to a $322 million cap over the life of the project; and

•	a drilling carry of up to $16 million on the drilling of the planned Mesozoic oil exploration well.

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

•	each field representing more than 1% of total proved reserves, as well as a selection of smaller fields, 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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•	372 MMBoe in the Tamar field, offshore Israel, which will begin converting to proved developed at first production, currently expected in second quarter 2013;

•	158 MMBoe in the DJ Basin, including Wattenberg, consisting of 958 horizontal Niobrara locations, which is equivalent to less than three years of drilling based on current plans;

•	106 MMBoe in the Marcellus Shale, consisting of 290 horizontal locations, which is equivalent to less than three years of drilling based on current plans;

•	74 MMBoe in Equatorial Guinea, 64% of which are in the Alba field with the remainder in the Alen field. The Alba reserves, which will be recovered from existing wells with a sanctioned compression project, will be reclassified to proved developed at start-up, currently expected in 2016. The Alen PUDs will be reclassified to proved developed at start-up, currently expected in 2013;

•	the above fields represent 98% of total PUDs. The remaining 2% is associated with ongoing developments in various areas scheduled in the next five years; and

•	PUDs include no material amounts which have remained undeveloped for five years or more.

•	recording of 135 MMBoe in the DJ Basin horizontal Niobrara program;

•	partially offset by negative revisions of 94 MMBoe in the DJ Basin due to our decision to terminate the legacy vertical drilling program and focus capital and drilling rigs on the horizontal development of the Niobrara;

•	recording of 51 MMBoe in the Marcellus Shale as a result of an ongoing development program with expansion into the wet gas area of the play;

•	recording of an additional 7 MMBoe at Tamar as a result of ongoing appraisal work, plus 1 MMBoe from other international areas;

•	conversion of 82 MMBoe into proved developed reserves, primarily related to ongoing development in the DJ Basin (19% of year-end 2011 PUDs converted) and Marcellus Shale (22% of year-end 2011 PUDs converted), the start-up of the Galapagos project in the deepwater Gulf of Mexico, and a pipeline pressure-reduction project in Equatorial Guinea;

•	the sale of 3 MMBoe from our non-core asset divestiture program;

•	positive revisions of 10 MMBoe, primarily due to increased recovery assumptions in the Marcellus Shale as a result of better than expected performance from existing wells; and

•	negative revisions of 7 MMBoe, primarily in the Marcellus Shale, due to changes in commodity prices.

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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 and natural gas reserves, including estimates of proved, proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in the standardized measure of discounted future net cash flows.

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

(2)	Natural gas 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.

(4)	Average crude oil sales prices reflect reductions of $1.32 per Bbl for 2010 from hedging activities. Average natural gas sales prices reflect a decrease of $0.01 per Mcf for 2010 from hedging activities. This price reduction resulted from losses that were previously deferred in AOCL. All hedge losses relating to US production had been reclassified to revenues by December 31, 2010.

(5)	Includes sales volumes through November 24, 2010. Our Block 3 PSC was terminated by the Ecuadorian government on November 25, 2010. Intercompany natural gas sales were eliminated for accounting purposes. Electricity sales are included in other revenues. See Exit from Ecuador above.

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(1)	Developed acres includes approximately 464,000 gross (214,000 net) in the Marcellus Shale that are held by the production of others.

(2)	A portion of the acreage has been assigned to a partner and the agreement is awaiting government approval.

(3)	The North Sea includes acreage in the UK and the Netherlands.

(1)	Represents acreage that will expire if no further action is taken to extend. Approximately 35% 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.

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(3)	Represents acreage that will expire if no further action is taken to extend. We are currently planning to drill an appraisal well in 2013. The result of this well will assist us in the evaluation of our acreage.

(4)

The acreage in Cameroon is comprised of our Tilapia PSC and YoYo mining concession. Pursuant to the Tilapia PSC, our first exploration period expires on July 6, 2013; however, we have the right to extend our acreage for two additional periods of two years each. Pursuant to our YoYo mining concession, development must commence prior to December 2014; we are actively engaged in negotiations to extend the term of the mining concession to 35 years.

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

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•	sale of approximately 2.7 Tcf (approximately 1.0 Tcf net to us) of natural gas to IEC over an approximate 15-year period. IEC has the option to increase this amount to 3.5 Tcf (approximately 1.3 net to us), under certain conditions;

•	sale of approximately 2.5 Tcf (approximately 0.9 Tcf net to us) of natural gas to additional customers. Most contracts provide for the sale of natural gas over a 15 to 17 year period. Some of the contracts provide for increase or reduction in total quantities and some are interruptible during certain contract periods; and

•	sales prices based on an initial base price subject to price indexation over the life of the contract and with a floor. The IEC contract also provides for price reopeners in the eighth and eleventh years with limits on the increase/decrease from the contractual price.

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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 Energy and Water Resources which regulates both 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 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;

•	various agencies in China which, under such laws as the Provisional Regulations on Administration and Management of the Abandonment of Offshore Oil and Gas Producing Facilities enacted in 2010, regulate our development and production activities offshore China;

•	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, 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, as amended, the Resource Conservation and Recovery Act, as amended, 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, which under the Endangered Species Act has authority over activities that may result in the take of an endangered 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 and natural gas 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 undesigned 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.

•	ensuring energy security in the economy;

•	providing a framework for substantial resource exports;

•	designating a certain percentage of production from each field for domestic natural gas demand;

•	maintaining competition in the different sectors of the local economy;

•	maximizing economic and political benefits; and

•	leveraging environmental advantages with respect to the use of natural gas.

•	as a rule, all reservoirs should be charged with supplying a certain percentage of natural gas to the local economy, with minimum requirements based on reservoir size (minimum of 25%-50%). The minimum supply obligations will not apply for reservoirs under a certain size (25 BCM) but the reservoirs will be required to be connected to the domestic

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•	a determination that the quantity of natural gas that should be guaranteed in favor of the local economy should be 450 BCM and that the quantity should be updated in five years;

•	the export of natural gas should be permitted as long as the quantity from all reservoirs does not exceed 500 BCM, which amount may be reassessed;

•	regulatory approval required for export, with export licenses eligible for periods up to 25 years;

•	there should be an absolute preference for the export of natural gas from a facility in an area under Israeli control, including Israel's exclusive economic zone, although further study of various export means (such as export from a foreign area governed by bilateral agreement) and statutory feasibility is necessary; and

•	steps should be taken to increase competition in the natural gas market.

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

•	Item 1A. Risk Factors – Federal or state hydraulic fracturing legislation could increase our costs or restrict our access to oil and gas reserves;

•	Item 1A. Risk Factors – Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner;

•	Item 1A. Risk Factors – We face various risks associated with the trend toward increased anti-development activity; 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;

•	OPEC spare capacity relative to global crude oil supply;

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

•	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;

•	the potential expansion of 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;

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•	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;

•	impact of conservation efforts on the ability to access government-owned and other lands for exploration and production activities; and

•	domestic and foreign governmental regulations and taxes.

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

•	curtailment or shut-in of our natural gas 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;

•	cause certain properties in our portfolio to become economically unviable;

•	cause us to delay or postpone some of our capital projects, including our horizontal Niobrara and Marcellus Shale, deepwater Gulf of Mexico, or international development projects;

•	cause significant reductions in our capital investment programs, resulting in a reduced ability to develop our reserves;

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

•	limit our access to sources of capital, such as equity and long-term debt.

•	asset impairment charges resulting from reductions in the carrying values of our oil and gas properties at the date of assessment, such as occurred in 2012, 2011, and 2010;

•	additional counterparty credit risk exposure on commodity hedges; or

•	a reduction in the carrying value of goodwill.

•	inability to attract and/or retain 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 could adversely affect project development;

•	lack of government approval for projects;

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

•	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 recommendations of Israel's Interministerial Committee to Examine Government Policy on Israel's Natural Gas Economy (Interministerial Committee), 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 foreign hydrocarbon-producing nations, such as expropriation or nationalization of assets or termination of contracts, such as the termination of our Block 3 PSC by the Ecuadorian government in 2010 pursuant to changes in Ecuador's hydrocarbon law;

•	disruptions caused by territorial or boundary disputes in certain international regions, including the Eastern Mediterranean, where Lebanon has made claims related to our projects in Israeli waters and the Turkish government in Ankara objected to exploratory activities conducted offshore the Republic of Cyprus;

•	changes in drilling or safety regulations in other countries as a result of the Deepwater Horizon Incident or other incidents that have occurred, such as offshore Brazil and in China's Bohai Bay, which could increase costs and development cycle time;

•	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, such as Israel; and

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

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•	restrict resource access or lease holding;

•	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 project 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 current 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;

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

•	adversely affect the price of our common stock.

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•	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 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 complete disruption of our business activities; and

•	capital market reassessment of risk and subsequent reallocation of capital to more stable areas making it more difficult for our partners to obtain financing for potential development projects.

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

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•	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;

•	release of pollutants;

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

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

•	theft or vandalism of oilfield equipment and supplies, especially in areas of increased activity such as the DJ Basin and Marcellus Shale;

•	hurricanes, cyclones, windstorms, or “superstorms”, such as Hurricane Sandy which occurred in 2012, which could affect our operations in areas such as the Gulf Coast, deepwater Gulf of Mexico, Marcellus Shale, Eastern Mediterranean or offshore China;

•	winter storms and snow which could affect our operations in the Rocky Mountain areas;

•	unseasonably warm weather, which could affect third party gathering and processing facilities, such as occurred in the Rocky Mountain areas during 2012;

•	volcanoes which could affect our operations offshore Equatorial Guinea;

•	flooding which could affect our operations in low-lying areas such as the Marcellus Shale;

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

•	other natural disasters.

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•	increase the costs of drilling exploratory and development wells;

•	cause delays in, or preclude, the development of our projects in the deepwater Gulf of Mexico or other locations, resulting in longer development cycle times;

•	result in additional operating costs;

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

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•	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.

•	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, 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 traditional sources of funding or make funding more expensive; and

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

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•	compromise of the security of our employees by subjecting them to detention, arrest, claims of espionage and/or prosecution;

•	loss of our license to operate in countries where the laws and regulations or terms of production sharing or other contracts prohibit disclosures of certain information, resulting in a reduction in our profitability;

•	decrease in our ability to compete for new sources of reserves with state-controlled national oil companies or large multi-national companies not subject to disclosures under the Final Rules; and

•	reduction in profitability and cash flows and a decrease in the price of our common stock.

•	increased regulation of our business;

•	increased regulation of the banking industry; and

•	increased corporate income taxes.

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•	delay or denial 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 us;

•	increased costs of doing business;

•	reduction in demand for our products; and

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

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

•	data corruption, communication interruption, or other operational disruption during drilling activities could result in a dry hole cost or even drilling incidents;

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

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•	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, such as recent changes in setback requirements expected to be approved by the COGCC, 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, such as the recent ban on hydraulic fracturing enacted by the City of Longmont, Colorado;

•	landowner opposition to infrastructure development, such as recent landowner challenges to the use of eminent domain to gain access to land for the extension of the Keystone pipeline through Texas, or to onshore delivery points in Israel;

•	regulation of federal land by the BLM, which has proposed rules for hydraulic fracturing on federally-owned land, and which can limit our access to a significant portion of our Nevada acreage;

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

•	disputes regarding leases, such as the Butler v. Powers case in Pennsylvania; 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 and natural gas 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, similar to that offshore the Shetland Islands in the North Sea, includes harsh weather and rough seas which could limit seismic and other exploration activities during certain periods; and

•	there have been numerous acts of piracy, kidnapping, civil strife, regional conflict, cross-border violence, and war, as well as violence associated with corruption, drug trafficking and regime changes in the countries of West Africa which could disrupt our operations offshore Sierra Leone.

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•	development drilling in emerging resource plays such as the Marcellus Shale may not result in commercially productive quantities of crude oil and natural gas reserves;

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we have less exploration and development experience in the Marcellus Shale than we have in other areas and limited information regarding ultimate recoverable reserves and production decline rates; therefore, our estimates of economically recoverable quantities of crude oil and natural gas reserves may vary substantially and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates;

•	the high level of current and planned development activity in the Marcellus Shale may result in increased competition for drilling rigs and oilfield services such as hydraulic fracturing, gathering, processing and/or transportation, thus hindering our ability to develop our reserves and market our production;

•	activism in New York, Pennsylvania and West Virginia against oil and gas development activities, particularly regarding the use of hydraulic fracturing, could, among other things, delay or limit our access to crude oil and natural gas reserves;

•	additional environmental regulation or legislation could result in additional development and/or production costs;

•	potential enactment of severance taxes or additional fees in Pennsylvania, such as the well impact fee enacted by the Pennsylvania legislature in 2012, would likely result in a lower rate of return on our development project; and

•	our inability to locate sufficient amounts of water, or dispose of or recycle water used in our operations, could hinder our ability to develop our reserves or increase our development and operating costs; and

•	development activity in the Marcellus Shale places additional burdens on our financial resources and internal financial controls.

•	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 revolving credit facility; and

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

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•	the European debt crisis persists, with governments and banks requiring more economic assistance;

•	fiscal situations are also worsening in OECD countries due to lingering effects of recession including slower growth rates;

•	Basel III banking regulation impacts the amount and nature of capital required to be held by banks;

•	quantitative easing programs generally weaken the currency of the country launching the stimulus, and discontinuance of such programs can result in spikes in interest rates;

•	the risk of a potential negative stock market event, such as a sharp price decline or even a “crash”, is intensified by lack of significant improvement in the US fiscal situation and fear that a combination of spending cuts and new taxes could push the country back into recession; and

•	interest rates could rise if the US debt ceiling is not raised in a timely manner.

•	if the debt ceiling is not raised in a timely manner, the US could default on its debt and/or experience a reduction in its credit rating, and interest rates could increase;

•	servicing the US debt diverts resources from investments that would spur economic growth;

•	increased borrowing means that the US government competes with businesses for financing and businesses may be unable to secure funds for expansion;

•	a federal deficit reduction program, if undertaken too rapidly, could put the economy back into recession; and

•	austerity measures undertaken to reduce the US deficit could result in increased social unrest, such as is occurring in the European Union.

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•	disruption of the Euro currency system and/or changes in currency regimes;

•	disruption of the payment and settlement system;

•	severe inflation due to currency depreciation;

•	loss of access to energy markets;

•	sovereign and corporate defaults on euro-denominated debt;

•	failures of banks or financial systems or reduced ability of banks to lend due to higher funding costs;

•	devaluation of assets; and

•	regional economic recession which could spread globally.

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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 and natural gas production;

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

•	attracting and retaining employees with certain skills.

•	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;

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•	unexpected drilling conditions;

•	pressure or other irregularities in formations;

•	equipment failures or accidents; and

•	adverse weather conditions.

•	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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•	our growth strategies;

•	our ability to successfully and economically explore for and develop crude oil and natural gas 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)

Charles D. Davidson was elected Chief Executive Officer of Noble Energy in October 2000 and Chairman of the Board in April 2001, also serving as President until April 2009 (at which time Mr. Stover assumed that position). Prior to October 2000, he served as President and Chief Executive Officer of Vastar Resources, Inc. from March 1997 to September 2000 (Chairman from April 2000) and was a Vastar Director from March 1994 to September 2000. From September 1993 to March 1997, he served as a Senior Vice President of Vastar. From 1972 to October 1993, he held various positions with ARCO.

(2)

David L. Stover was elected President and Chief Operating Officer of Noble Energy in April 2009. Prior thereto, he served as Executive Vice President and Chief Operating Officer of Noble Energy from August 2006 to April 2009. He served as Senior Vice President of North America and Business Development from July 2004 through July 2006, and he served as Noble Energy’s Vice President of Business Development from December 2002 through June 2004. Previous to his employment with Noble Energy, he was employed by BP America, Inc. as Vice President, Gulf of Mexico Shelf from September 2000 to August 2002. Prior to joining BP, Mr. Stover was employed by Vastar, as Area Manager for Gulf of Mexico Shelf from April 1999 to September 2000, and prior thereto, as Area Manager for Oklahoma/Arklatex from January 1994 to April 1999. From 1979 to 1994, he held various positions with ARCO.

(3)

Kenneth M. Fisher was elected Senior Vice President and Chief Financial Officer of Noble Energy in November 2009. Prior to joining Noble Energy, Mr. Fisher served as Executive Vice President of Finance for Upstream Americas for Shell from July 2009 to November 2009. Prior to his most recent position with Shell, Mr. Fisher served as Director of Strategy & Business Development for Royal Dutch Shell plc in The Hague from August 2007 to July 2009.  He served as Executive Vice President of Strategy & Portfolio for Shell’s downstream business in London from January 2005 to August 2007. Mr. Fisher joined Shell in August 2002 and served as Chief Financial Officer for Shell Oil Products U.S. until December 2004. As Chief Financial Officer for Shell Oil Products U.S., he was responsible for U.S. oil products finance, information technology and contracting and procurement activities. Prior to joining Shell, he held positions of increasing responsibility with General Electric Company (GE) from 1984 to 2002, including Vice President and Chief Financial Officer of the Aircraft Engines Services division and Director of Finance & Business Development of GE’s Asia Pacific plastics business.

(4)

Ted D. Brown was elected a Senior Vice President of Noble Energy in April 2008 and is currently responsible for the Northern Region of our North America division. He served as Vice President, responsible for the same region, from August 2006 to April 2008 and as a vice president of that division since joining Noble Energy upon our acquisition of Patina Oil & Gas Corporation (Patina) in May 2005. He served as Senior Vice President of Patina from July 2004 to May 2005. Prior thereto he served as Director, Piceance Basin Asset along with Engineering Manager for Williams and Barrett Resources since 1993 and, before that, in various positions with Union Pacific Resources and Amoco Production Company.

(5)	Rodney D. Cook was elected a Senior Vice President of Noble Energy in April 2008 and is currently responsible for the International division. He served as Vice President of Noble Energy, responsible for the Southern Region of our North America division, from August

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(6)

Susan M. Cunningham was elected a Senior Vice President of Noble Energy in April 2001 and is currently responsible for our world-wide exploration. Prior to joining Noble Energy, Ms. Cunningham was Texaco’s Vice President of worldwide exploration from April 2000 to March 2001. From 1997 through 1999, she was employed by Statoil, beginning in 1997 as Exploration Manager for deepwater Gulf of Mexico, appointed a Vice President in 1998 and responsible, in 1999, for Statoil’s West Africa exploration efforts. She joined Amoco Canada in 1980 as a geologist and held various exploration and development positions with Amoco Production Company until 1997.

(7)

Arnold J. Johnson was elected Senior Vice President, General Counsel and Secretary of Noble Energy in July 2008. Prior thereto, he served as Vice President, General Counsel and Secretary of Noble Energy since February 2004. He served as Associate General Counsel and Assistant Secretary of Noble Energy from January 2001 through January 2004. Previous to his employment with Noble Energy, he served as Senior Counsel for BP America, Inc. from October 2000 to January 2001. Mr. Johnson held several positions as an attorney for Vastar and ARCO from March 1989 through September 2000, most recently as Assistant General Counsel and Assistant Secretary of Vastar from 1997 through 2000. From 1980 to March 1989, he held various positions with ARCO.

(8)

Andrea Lee Robison was elected a Vice President of Noble Energy in November 2007 and is responsible for Human Resources and Administration. Prior thereto, she served as Director of Human Resources from May 2002 through October 2007. Prior to joining us, Ms. Robison was Manager of Human Resources for the Gulf of Mexico Shelf for BP America, Inc. from September 2000 through April 2002. Prior to her employment at BP, she served as HR Director at Vastar from 1997 through September 2000, and Compensation Consultant from January 1994 through 1996. From 1980 through 1993, she held various positions with ARCO.

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

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(1)	Prices through 2010 include effects of oil and gas hedging activities. See Item 8. Financial Statements and Supplementary Data – Note 10.  Derivative Instruments and 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.

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•	net income over $1.0 billion (including $965 million from continuing operations) as compared with $453 million (including $412 million from continuing operations) for 2011 ;

•	dry hole cost of $155 million, as compared with $105 million for 2011;

•	gain on divestitures of $154 million as compared with $25 million for 2011;

•	asset impairment charges of $104 million as compared with $757 million for 2011;

•	gain on commodity derivative instruments of $75 million (including unrealized mark-to-market gain of $109 million) as compared with $42 million gain on commodity derivative instruments (including unrealized mark-to-market loss of $22 million) for 2011;

•	diluted earnings per share of $5.71, as compared with $2.54 for 2011;

•	cash flows provided by operating activities of $2.9 billion, as compared with $2.2 billion in 2011;

•	received $1.2 billion in proceeds from divestments of non-core assets, as compared with $77 million in 2011;

•	capital spending on a cash basis of $3.7 billion as compared with $3.1 billion in 2011 (including $527 million for the Marcellus Shale asset acquisition);

•	exercised option to increase credit facility from $3.0 billion to $4.0 billion, enhancing our liquidity position;

•	ending cash and cash equivalents balance of $1.4 billion at December 31, 2012, as compared with $1.5 billion at December 31, 2011;

•	total liquidity of $5.4 billion at December 31, 2012, consisting of year-end cash balance plus funds available under our credit facility, as compared with $4.5 billion at December 31, 2011; and

•	year-end ratio of debt-to-book capital of 33%, as compared with 38% at December 31, 2011.

•	total sales volumes from continuing operations of 239 MBoe/d, a 12% increase as compared with 2011;

•	liquids represent 46% of total sales volumes from continuing operations as compared to 37% in 2011; and

•	year-end proved reserves of 1.2 BBoe, a decrease of 2% from year-end 2011.

•	increased DJ Basin (Wattenberg) total sales volumes to 77 MBoe/d, net, with horizontal production contributing 28 MBoe/d, net;

•	spud 200 and completed 193 horizontal wells in the DJ Basin;

•	expanded the Northern Colorado acreage position by 26,000 net acres to 230,000 net acres, where recent horizontal Niobrara results indicate recoveries comparable to Wattenberg;

•	Marcellus Shale production grew to 92 MMcfe/d, net, as compared with 19 MMcfe/d, net, in 2011;

•	drilled to total depth 89 and completed 71 gross horizontal wells in the Marcellus Shale and initiated production from the wet gas area;

•	experienced higher recovery rates than anticipated in the DJ Basin and Marcellus Shale;

•	entered new exploration area in Northeast Nevada; and

•	completed non-core onshore asset dispositions.

•	announced a discovery at the Big Bend prospect;

•	Galapagos produced at an average rate of 6 MBbl/d of crude oil, net; and

•	acquired six deepwater Gulf of Mexico blocks at the Outer-Continental Shelf Sale 222;

•	discovery of a new crude oil reservoir at Carla, offshore Equatorial Guinea;

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•	Aseng field, offshore Equatorial Guinea, produced at an average gross rate of 62 MBbl/d of crude oil (21 MBbl/d, net);

•	acceleration of Alen development, offshore Equatorial Guinea;

•	installed the Tamar platform and initiated the commissioning process;

•	announced a strategic development partner for the Leviathan project, offshore Israel;

•	announced the Tanin natural gas discovery, offshore Israel;

•	entered into new positions offshore Falkland Islands and Sierra Leone;

•	secured contract with new-build drillship capable of reaching deep oil targets in the Eastern Mediterranean; and

•	completed the sale of our Dumbarton and Lochranza assets in the North Sea.

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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;

•	timing of major development project completion and initial production, including Tamar, offshore Israel, and Alen, offshore Equatorial Guinea, which are scheduled to begin producing in 2013;

•	ongoing development activity in the Wattenberg area and horizontal drilling in the Niobrara formation in the DJ Basin;

•	pace of increase of development activity in both wet gas and dry gas areas of the Marcellus Shale;

•	divestments of non-core operating assets;

•	natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations, and the Mari-B field in Israel (See Items 1. and 2. Business and Properties - Delivery Commitments);

•	variations in sales volumes of natural gas from the Alba field in Equatorial Guinea related to potential downtime at the methanol, LPG and/or LNG plants;

•	Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth, production rates from the Mari-B, Noa and Pinnacles wells, and anticipated production from Tamar, offshore Israel;

•	variations in West Africa sales volumes due to potential FPSO downtime and timing of liftings;

•	potential hurricane-related volume curtailments in the deepwater Gulf of Mexico and Gulf Coast areas;

•	potential winter storm-related volume curtailments in the Rocky Mountain and/or Marcellus Shale areas of our US operations;

•	third party facilities reliability in the Wattenberg and/or Rocky Mountain areas of our US properties which may cause restrictions or interruptions in mid-stream processing facilities;

•	potential pipeline and processing facility capacity constraints in the Rocky Mountain and/or Marcellus Shale areas of our US operations;

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

•	potential purchases of producing properties; and

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

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•	commodity prices, including price realizations on specific crude oil and natural gas production including the impact of NGLs;

•	cash flows from operations;

•	operating and development costs and possible inflationary pressures;

•	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;

•	increase in exploration activities in new areas, including offshore Sierra Leone and the Falkland Islands;

•	availability of financing;

•	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, including implementation of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which has resulted in significant derivatives regulations and disclosure requirements, on our business practices.

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•	We are subject to increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs; and

•	The adoption of GHG emission or other environmental legislation could result in additional operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and reduce demand for the crude oil and natural gas we produce.

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•	$819 million increase in total revenues due to higher sales volumes and higher average realized crude oil prices;

•	$129 million increase in gain on divestitures;

•	$33 million increase in gain on commodity derivative instruments; and

•	$653 million decrease in asset impairment charges;

•	$115 million increase in total production expense;

•	$132 million increase in exploration expense;

•	$492 million increase in DD&A expense; and

•	$45 million increase in general and administrative expense.

•	$43 million increase in total production expense;

•	$35 million increase in exploration expense;

•	$59 million increase in DD&A expense;

•	$66 million increase in general and administrative expense;

•	$88 million decrease in net gain on asset sales;

•	$613 million increase in asset impairment charges; and

•	$115 million decrease in gain on commodity derivative instruments;

•	$691 million increase in total revenues due primarily to higher commodity prices and higher sales volumes.

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

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

(3)	Includes sales volumes through November 24, 2010. Our Block 3 PSC was terminated by the Ecuadorian government on November 25, 2010. Intercompany natural gas sales were eliminated for accounting purposes. Electricity sales are included in other revenues. See Item 8. Financial Statements and Supplementary Data - Note 3.  Acquisitions and Divestitures.

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•	higher sales volumes in the DJ Basin attributable to the acceleration of our horizontal drilling programs in the Wattenberg area;

•	commencement of production at Galapagos and South Raton in the deepwater Gulf of Mexico which increased production by approximately seven MBoe/d, net, during 2012;

•	higher sales volumes in Equatorial Guinea due to the commencement of oil production at Aseng during the fourth quarter of 2011, which impacted our sales volumes by approximately 21 MBbl/d, net, in 2012 as compared with 2011; and

•	a 2% increase in total consolidated average realized prices primarily due to higher Brent pricing resulting from the global economic recovery

•	reduction in sales volumes due to the sales of non-core, onshore US properties during the third quarter of 2012;

•	a volume reduction in the Gulf of Mexico of nearly seven MBoe/d as a result of shut-ins due to Hurricane Isaac; and

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

•	a 31% increase in total consolidated average realized prices due to increased demand resulting from the global economic recovery;

•	higher sales volumes in the DJ Basin, including a 21% increase in Wattenberg sales volumes, attributable to the continued acceleration of our horizontal Niobrara development project; and

•	higher sales volumes in Equatorial Guinea due to a higher number of liftings from our Alba field and due to the commencement of oil production at Aseng which impacted our sales volumes by approximately 9 MBbl/d in the fourth quarter;

•	a decrease in onshore US volumes due to the divestment of non-core oil assets; and

•	a decrease in deepwater Gulf of Mexico volumes due to natural field decline and third party downstream facility constraints.

•	decreases in US average realized prices primarily due to oversupply and above average levels of natural gas in storage;

•	lower sales volumes due to the sales of non-core onshore US properties during the third quarter of 2012;

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•	lower sales volumes in the Wattenberg and Rocky Mountain areas of our US operations due to third-party processing facility constraints;

•	lower sales volumes from the Alba field, offshore Equatorial Guinea, due to scheduled maintenance activities at the non-operated Alba facilities; and

•	lower sales volumes in Israel due to a reduction in the rate of production from the Mari-B field in order to manage the reservoir;

•	higher sales volumes attributable to the acceleration of our horizontal drilling programs in the Wattenberg area; and

•	new sales volumes from Marcellus Shale producing properties which we acquired September 30, 2011 and current Marcellus Shale development activities, which added 90 MMcf/d, net to our sales volumes for 2012.

•	higher natural gas prices in Israel which benefit from strong global liquids markets;

•	an increase in Israel sales volumes due to an increase in demand for our natural gas driven by higher electricity production and lower levels of competitor natural gas imports from Egypt;

•	higher sales volumes in the DJ Basin, including a 10% increase in Wattenberg sales volumes, attributable to the continued acceleration of our vertical and horizontal Niobrara drilling programs in the Wattenberg area;

•	sales volumes from Marcellus Shale producing properties which we acquired September 30, 2011 and which added 19 MMcf/d to our 2011 sales volumes; and

•	higher sales volumes in Equatorial Guinea as compared with 2010, during which time the Alba field experienced a planned shut-down for facilities maintenance and repair;

•	a decrease in US realized natural gas prices which declined during 2011 primarily due to oversupply;

•	a decrease in onshore US sales volumes due to the sale of certain non-core Oklahoma and Illinois Basin assets in 2010; and

•	natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas.

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

(2)	Other international includes China and unallocated expenses incurred at the corporate level.

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

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•	higher sales volumes from the Wattenberg area due to ongoing development activities accounted for an increase of $24 million in US lease operating expense;

•	new production at Galapagos and higher production handling costs at Swordfish, deepwater Gulf of Mexico, accounted for an increase of $22 million;

•	a full year of production from Marcellus Shale properties acquired in 2011, and additional development activity accounted for an increase of $17 million;

•	lease operating expense associated with the Aseng field, offshore Equatorial Guinea, which began producing in November 2011, accounted for an increase of $36 million; and

•	the start-up of the Noa and Pinnacles wells, offshore Israel, in second quarter of 2012 accounted for an increase of $8 million;

•	lower volumes in the US due to the sale of non-core onshore US properties during the third quarter of 2012.

•	higher US sales volumes from the DJ Basin due to ongoing development activities;

•	higher sales volumes in Equatorial Guinea and Israel; and

•	higher operating costs associated with the Aseng field which began producing in November 2011;

•	the sale of certain Oklahoma and Illinois Basin assets in 2010, which had higher lease operating costs.

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(1)	West Africa includes Equatorial Guinea, Cameroon, Sierra Leone, and Senegal/Guinea-Bissau.

(2)	Eastern Mediterranean includes Israel and Cyprus.

(3)	Other International includes various international new ventures such as offshore Nicaragua and offshore Falkland Islands.

•	US dry hole expense associated with the Deep Blue exploratory well (deepwater Gulf of Mexico) totaled $117 million. Although Deep Blue was successful in locating hydrocarbons, we decided not to develop the prospect due to near-term lease expiration as well as other considerations;

•	dry hole expense in West Africa related to the Trema exploratory well, which found noncommercial quantities of hydrocarbons, totaled $32 million;

•	exploration expense in West Africa includes $40 million for the non-operated AGC Profond block offshore Senegal/Guinea-Bissau, which was written off during the third quarter of 2012 when we decided not to proceed with additional appraisal activities. We relinquished our acreage;

•	seismic expenditures related to the deepwater Gulf of Mexico lease sale and international new ventures; and

•	exploration expense also includes staff expense associated with new ventures and corporate expenditures.

•	US dry hole expense was associated with the Rocky Mountain area and the Redrock exploration well in the deepwater Gulf of Mexico, which we decided not to pursue for development due to the significant decline in natural gas prices;

•	dry hole expense in West Africa related to the Kora-1 exploration well offshore Senegal/Guinea-Bissau and the Bwabe exploration well offshore Cameroon, which found noncommercial quantities of hydrocarbons;

•	seismic expenditures related to acquisition of information for Wattenberg, Rocky Mountain and deepwater Gulf of Mexico areas in the US, offshore Nicaragua, offshore France, and offshore Cyprus; and

•	increases in staff expense were due to new ventures mainly offshore Nicaragua and offshore France.

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(1)	DD&A expense includes accretion of discount on asset retirement obligations of $22 million in 2012, $13 million in 2011, and $13 million in 2010.

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

•	higher sales volumes in the DJ Basin onshore US accounted for $189 million of the increase and the addition of DD&A expense related to the Marcellus Shale accounted for $46 million of the increase;

•	the start up of Noa and Pinnacles (offshore Israel), which have higher DD&A rates, accounted for $86 million of the increase;

•	the start up of Galapagos and South Raton in the deepwater Gulf of Mexico, which have higher DD&A rates, accounted for $92 million of the increase;

•	a full year of production from the Aseng field, offshore Equatorial Guinea, which includes the Aseng FPSO in its depreciation base, accounted for $183 million of the increase; and

•	higher costs associated with development activities in China;

•	the impact of sales of non-core, onshore US properties during 2012.

•	higher sales volumes in the DJ Basin of our onshore US operations resulting from ongoing capital spending;

•	higher sales volumes in Equatorial Guinea and the startup of the Aseng field which includes the Aseng FPSO in its depreciation base;

•	higher costs associated with development activities in China; and

•	the impact of negative reserves revisions at December 31, 2011, due to revised performance expectations in the North Sea and China;

•	lower sales volumes in the deepwater Gulf of Mexico, Gulf Coast, and Mid-Continent areas of our US operations resulting from natural field decline.

(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. During 2012, the nearby Bligh well, a potential co-development candidate for Selkirk, was drilled. Bligh encountered hydrocarbons but disappointingly tight non-commercial reservoirs. Therefore, we determined that Selkirk was uneconomic for joint development.

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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 Wattenberg and focus on the horizontal development of the Niobrara; 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, 2011 include a negative revision of 28 MMBoe, due primarily to reclassifications of proved undeveloped reserves in Wattenberg that are no longer expected to be developed within five years due to additional shifting of activity from vertical to horizontal development, a negative revision of 10 MMBoe due to reduced activity assumptions for dry gas properties onshore US, as well as other lesser revisions in various other areas related to well performance and changes in commodity prices; and

•

changes for the year ended December 31, 2010 included a positive revision of 43 MMBoe due to higher year-end commodity prices, a negative revision of 30 MMBoe due to reclassifications of proved undeveloped reserves to probable reserves as a result of the SEC’s five year development rule, a negative revision of 7 MMBoe due to a change in the likelihood that the Noa field, offshore Israel, would be pursued for development, and a negative revision of 2 MMBoe due to well performance.

•	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, 56 MMBoe related to ongoing development of the Marcellus Shale, 7 MMBoe related to the ongoing appraisal of Tamar, and 6 MMBoe for other projects;

•	changes for the year ended December 31, 2011 included increases of 97 MMBoe in the onshore US, primarily associated with horizontal drilling in the DJ Basin and development activities in the Marcellus Shale, 80 MMBoe at Tamar due to appraisal activities, and 3 MMBoe for other projects; and

•

changes for the year ended December 31, 2010 included an increase of 48 MMBoe, which were primarily driven by the execution of low-risk development projects onshore in Wattenberg and the Rocky Mountain area, an increase of 286 MMBoe related to the initial recording of reserves for the Tamar field offshore Israel, and an increase of approximately 27 MMBoe related to the initial recording of reserves for the Alen field, offshore Equatorial Guinea.

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•	the Marcellus Shale asset acquisition in 2011; and

•	the DJ Basin asset acquisition in 2010.

•	the sale of non-core, onshore US assets in the Kansas, western Oklahoma, west Texas and Wyoming areas and the North Sea in 2012; and

•	the sale of non-core assets in the Mid-Continent and Illinois Basin areas in 2010.

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(1)	See Credit Facility below.

(2)	Total debt includes Aseng FPSO lease obligation and remaining CONSOL installment payments 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 2012 includes $85 million primarily related to additional acreage in the DJ Basin and other onshore US lease acquisitions, $25 million related to our entry into a farmout agreement offshore Falkland Islands, $28 million in bonuses paid on deepwater Gulf of Mexico lease blocks acquired in the June 2012 lease sale, $3 million related to our entry into a license offshore Sierra Leone (West Africa), offset by downward adjustments related to the Marcellus Shale acquisition.

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(2)	Proved property acquisition cost includes $386 million related to the Marcellus Shale asset acquisition in 2011 and $352 million related to DJ Basin asset acquisition in 2010.

(3)	In connection with the Marcellus Shale joint venture, we acquired a 50% interest in CONE which is accounted for using the equity method. CONE constructs, owns and operates gathering lines and facilities related to the Marcellus Shale development.

(4)	Relates to estimated construction progress on the Aseng FSPO, which went into service during the fourth quarter of 2011.

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•	$361 million reduction in debt due to the first installment payment to CONSOL as well as payment under our FPSO lease obligation; and

•	$1.0 billion increase in shareholders’ equity from current year net income;

•	$164 million decrease in shareholders’ equity from dividends paid.

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(1)	Long-term debt excludes our Aseng FPSO lease obligation. See Item 8. Financial Statements and Supplementary Data – Note 12. Long-Term Debt.

(2)	Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2012. See Item 8. Financial Statements and Supplementary Data – Note 12. Long-Term Debt.

(3)	Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Item 8. Financial Statements and Supplementary Data – Note 12. Long-Term Debt.

(4)	Drilling and equipment obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related equipment for exploratory and development drilling activities. See Item 8. Financial Statements and Supplementary Data – Note 20.  Commitments and Contingencies.

(5)	Purchase obligations represent 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 Item 8. Financial Statements and Supplementary Data – Note 20.  Commitments and Contingencies.

(6)	Transportation and gathering obligations represent minimum charges for firm transportation and gathering agreements.  See Item 8. Financial Statements and Supplementary Data – Note 20.  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 20.  Commitments and Contingencies.

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(8)	The table excludes deferred compensation liabilities of $229 million and accrued benefit costs of $116 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data – Note 14.  Stock-Based and Other Compensation Plans.

(9)	Asset retirement obligations are discounted. See Item 8. Financial Statements and Supplementary Data – Note 11.  Asset Retirement Obligations.

(10)	Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2012. Our remaining commodity derivative instruments were in a net receivable position at December 31, 2012. See Item 8. Financial Statements and Supplementary Data – Note 10.  Derivative Instruments and Hedging Activities.

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

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

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

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(1)	Other revenues consist primarily of electricity sales from the Machala power plant, located in Machala, Ecuador, through May 2011. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation and changes in the allowance for doubtful accounts. In May 2011, we transferred our assets in Ecuador to the Ecuadorian government.

(2)	Amounts relate to rig stand-by expense incurred due to the deepwater Gulf of Mexico drilling moratorium.

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

(4)	Interest income for 2010 includes $3 million related to the refund of deepwater Gulf of Mexico royalties.

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(1)	Increase from December 31, 2011 is due to reclassification of deferred income tax assets from long-term to short-term as certain foreign entities are estimated to begin utilizing net operating loss carryforwards in 2013.

(2)	Amounts represent the costs incurred to date of the Leviathan-2 appraisal well and expected well abandonment costs in excess of the insurance deductible less insurance proceeds received to date. See Note 11.  Asset Retirement Obligations.

(3)	Assets held for sale consist primarily of North Sea oil and gas properties, and liabilities associated with assets held for sale consists primarily of asset retirement obligations. See Note 3. Acquisitions and Divestitures.

(4)	See Note 3.  Acquisitions and Divestitures and Note 12. Long-Term Debt.

(5)	Amount includes liabilities accrued under our defined benefit pension plan, restoration plan, and other postretirement benefit plans. See Note 14.  Stock-Based and Other Compensation Plans.

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(1)	See Note 3.  Acquisitions and Divestitures and Note 12. Long-Term Debt.

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(1)	Total reflects impact of $17 million imputed interest on CONSOL installment payments.

•	estimated quantities of crude oil and natural gas reserves prepared by our qualified petroleum engineers;

•	management’s estimates of future commodity prices based on NYMEX Henry Hub natural gas futures prices and adjusted for estimated location and quality differentials;

•	estimated future production rates based on our experience with similar properties which we operate; and

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•	estimated timing and amounts of future operating and development costs based on our experience with similar properties which we operate.

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(1)	During 2011, recovery of approximately $19 million for outstanding receivables was included in the final terms of our agreement to transfer our assets and the associated electricity concession and PSC to the Ecuadorian government. See Note 3.  Acquisitions and Divestitures.

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(1)	Amount primarily represents Deep Blue (deepwater Gulf of Mexico) exploratory well costs capitalized prior to December 31, 2012. Although hydrocarbons were found in both the initial exploration well and subsequent sidetrack, we and our partners decided not to proceed with additional appraisal activities.

(2)	Amount relates to Selkirk (North Sea) exploratory well costs capitalized prior to December 31, 2012. During the fourth quarter of 2012, our Selkirk field, which is included in discontinued operations, was determined to be uneconomic for joint development and was charged to exploration expense. See Note 3.  Acquisitions and Divestitures.

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

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

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

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(1)	Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. All net derivative gains and losses that were deferred in AOCL as a result of previous cash flow hedge accounting, had been reclassified to earnings by December 31, 2010.

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(1)	Our Credit Agreement provides for a $4.0 billion unsecured revolving Credit Facility. The Credit Facility is available for general corporate purposes.

(2)	Imputed rate based on the prevailing market rates for similar debt instruments at the date of assessment.

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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 years US Treasury securities as of the date of grant.

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

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

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

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

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

(1)	Excludes Aseng FPSO lease obligation. No floating rate debt was outstanding at December 31, 2012 or December 31, 2011. See Note 12. Long-Term Debt.

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(1)	Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 12. Long-Term Debt.

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(2)	Other International includes China and the North Sea.

(3)	The 2010 US revisions include the impacts of higher prices and additional NGLs recorded in Wattenberg, partially offset by the reclassification of 16 MMBbls of PUD reserves to probable reserves, primarily in Wattenberg, as a result of the SEC's five year development rule.  The 2010 revisions to other international reserves are related to performance revisions in China and the North Sea.

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(4)	The 2010 increase in US proved reserves relates to continuing development of onshore assets, primarily in the DJ Basin. The 2010 increase in Equatorial Guinea reserves includes 26 MMBbl for the Alen field.

(5)	The 2010 increase relates to the DJ Basin asset acquisition. See Note 3.  Acquisitions and Divestitures.

(6)	In 2010, we sold non-core, onshore US assets in the Mid-Continent and Illinois Basin.

(7)	Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2012, 2011 and 2010.

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(1)	Other International includes China, Ecuador (at December 31, 2009), and the North Sea. See Note 3.  Acquisitions and Divestitures and Note 4. Asset Impairments.

(2)

The 2010 US revisions are a combination of increases from higher natural gas prices, which were more than offset by gas shrinkage from additional NGLs recorded in Wattenberg and the reclassification of 85 Bcf of PUDs to probable reserves, primarily in Wattenberg, as a result of the SEC's five year development rule. Equatorial Guinea’s positive revision in 2010 is primarily due to additional production allowances related to LNG sales.  Israel’s revisions in 2010 reflected a change in the likelihood that the Noa field would be developed.

(3)	The 2010 increase in US proved reserves is due to continuing development of onshore assets, primarily in the DJ Basin, Piceance Basin, and East Texas. The 2010 increase in Israel is due to the recording of initial reserves at the Tamar development.

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(4)	The increases relate to our DJ Basin asset acquisition in 2010 and our Marcellus Shale asset acquisition in 2011. See Note 3.  Acquisitions and Divestitures.

(5)	In 2010, we sold non-core, onshore US assets in the Mid-Continent and Illinois Basin. Other International sales in 2010 include 160 Bcf due to the termination of the Block 3 PSC by the Ecuadorian government.

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(1)	Other International includes the North Sea, Ecuador (through November 24, 2010), China, Cameroon, Cyprus, Senegal/Guinea-Bissau, Nicaragua, Falkland Islands, Sierra Leone and other new ventures. See Note 3.  Acquisitions and Divestitures.

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

(3)	During 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 cannot conclude it is more likely than not that some portion or all of the deferred tax assets will be realized.

(4)	Results of operations exclude the mark-to-market gain or loss on certain commodity derivative instruments not designated as cash flow hedges, corporate overhead and interest costs. See Note 10.  Derivative Instruments and Hedging Activities.

(5)	Includes impact resulting from applying cash flow hedge accounting for related commodity derivative instruments. See Note 10.  Derivative Instruments and Hedging Activities.

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(1)	Costs incurred include capitalized and expensed items.

(2)	Other International includes Cameroon, China, Cyprus, Ecuador (through November 24, 2010), Falkland Islands, the North Sea, Senegal/Guinea-Bissau, Nicaragua, Sierra Leone and other new ventures. See Note 3.  Acquisitions and Divestitures.

(3)	Proved property acquisition costs include $386 million related to the Marcellus Shale asset acquisition in 2011 and $352 million related to the DJ Basin asset acquisition in 2010.

(4)

2012 unproved property acquisition costs for the US include: $63 million related to expanding our position in the DJ Basin, $28 million for deepwater Gulf of Mexico lease blocks, and $27 million related to other onshore US, offset by a downward purchase price adjustments of $50 million related to our Marcellus Shale acquisition. 2012 unproved property acquisition costs for Other International include $25 million related to our position in Falkland Islands

(5)	2012 exploration costs include drilling and completion of $102 million in Israel, $71 million in Falkland Islands, $40 million in Equatorial Guinea, $36 million in the DJ Basin, and $13 million in Cyprus.

(6)	Worldwide development costs include amounts spent to develop PUDs of approximately $1.8 billion in 2012, $1.4 billion in 2011 and $1.1 billion in 2010.

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(1)	Unproved oil and gas properties includes $740 million, of which $734 million is related to Marcellus Shale, at December 31, 2012, and $874 million, of which $792 million is related to Marcellus Shale, at December 31, 2011, remaining from the allocation of costs to unproved properties acquired in previous acquisitions.

(2)	Proved oil and gas properties include asset retirement costs of $334 million and $310 million at December 31, 2012 and 2011, respectively.

(3)	Includes $200 million of proved oil and gas properties and $160 million of accumulated DD&A related to the North Sea classified as assets held for sale at December 31, 2012. See Note 3.  Acquisitions and Divestitures.

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(1)	Other International includes China and the North Sea. See Note 3.  Acquisitions and Divestitures.

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

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

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(1)	Other International includes China and the North Sea. See Note 3.  Acquisitions and Divestitures.

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(1)	First quarter 2012 included the following:

•	$96 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $73 million (See Note 10.  Derivative Instruments and Hedging Activities).

•	$73 million asset impairment charges (See Note 4. Asset Impairments);

•	$276 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $277 million (See Note 10.  Derivative Instruments and Hedging Activities); and

•	$9 million pre-tax gain on sale of non-core onshore US assets (See Note 3.  Acquisitions and Divestitures).

•	$135 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $131 million (See Note 10.  Derivative Instruments and Hedging Activities); and

•	$157 million pre-tax gain on sale of non-core onshore US assets (See Note 3.  Acquisitions and Divestitures).

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•	$31 million impairment charges (See Note 4. Asset Impairments);

•	$13 million pre-tax loss on sale of non-core onshore US asset, due to post closing adjustments (See Note 3.  Acquisitions and Divestitures); and

•	$30 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $36 million (See Note 10.  Derivative Instruments and Hedging Activities).

(2)	First quarter 2011 included the following:

•	$8 million impairment charges (See Note 4. Asset Impairments); and

•	$286 million loss on commodity derivative instruments, including unrealized mark-to-market loss of $303 million (See Note 10.  Derivative Instruments and Hedging Activities).

•	$131 million impairment charges (See Note 4. Asset Impairments);

•	$143 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $142 million (See Note 10.  Derivative Instruments and Hedging Activities); and

•	$25 million pre-tax gain on divestitures due to the completed transfer of assets and exit from Ecuador (See Note 3.  Acquisitions and Divestitures).

•	$322 million gain on commodity derivative instruments, including unrealized mark-to-market gain of $300 million (See Note 10.  Derivative Instruments and Hedging Activities).

•	$620 million asset impairment charges (See Note 4. Asset Impairments); and

•	$137 million loss on commodity derivative instruments, including unrealized mark-to-market gain of $44 million (See Note 10.  Derivative Instruments and Hedging Activities).

(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 calculations for the three months ended June 30, 2012 excludes a deferred compensation gain of $7 million, net of tax, and for the three months ended June 30 and September 30, 2011 exclude deferred compensation gains of $4 million and $12 million, respectively, 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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