Items 1 and 2. BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc. and Phillips Petroleum Company. The merger between Conoco and Phillips was consummated on August 30, 2002.

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our “Downstream business”), were transferred to Phillips 66. As a part of our strategic asset disposition program, in the fourth quarter of 2012, we agreed to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Nigerian and Algerian businesses. Results of operations related to Phillips 66, Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Annual Report on Form 10-K. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Headquartered in Houston, Texas, we have operations and activities in 30 countries. Our key focus areas include safely operating producing assets, executing major developments and exploring for new resources in promising areas. Our portfolio primarily includes legacy assets in North America, Europe, Asia and Australia; growing North American shale and oil sands businesses; several major international developments; and a global exploration program.

At December 31, 2012, ConocoPhillips employed approximately 16,900 people worldwide.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 25—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

We explore for, produce, transport and market crude oil, bitumen, natural gas, liquefied natural gas (LNG) and natural gas liquids on a worldwide basis. At December 31, 2012, our continuing operations were producing in

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the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Malaysia, Qatar, Libya and Russia.

Our operating segments were realigned upon the separation of Phillips 66, and as a result, all prior periods presented have been restated. We manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International.

The information listed below appears in the “Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements and is incorporated herein by reference:

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The following table is a summary of the proved reserves information included in the “Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements. Approximately 80 percent of our proved reserves are located in politically stable countries that belong to the Organization for Economic Cooperation and Development. Natural gas reserves are converted to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance the understanding of the table below.

In 2012, worldwide production, including our share of equity affiliates, was 1,578 thousand barrels of oil equivalent per day (MBOED), a 3 percent decrease from 2011 production of 1,619 MBOED. Production from continuing operations for 2012 averaged 1,527 MBOED, compared with 1,561 MBOED in 2011. Average production from continuing operations decreased 2 percent in 2012, primarily as a result of normal field decline, the impact from asset dispositions and higher planned and unplanned downtime. These decreases were largely offset by additional production from major developments, mainly from shale plays in the Lower 48 and ramp-up of new phases at FCCL, the resumption of production in Libya following a period of civil unrest in 2011, and increased drilling programs in the Lower 48.

Our worldwide annual average crude oil sales price from continuing operations remained relatively flat in 2012, from $105.52 per barrel in 2011 to $105.72 per barrel in 2012, while worldwide average annual natural gas liquids prices from continuing operations decreased 17 percent, from $55.73 per barrel in 2011 to $46.36 per barrel in 2012. Our average annual worldwide natural gas sales price from continuing operations decreased 6 percent, from $5.80 per thousand cubic feet in 2011 to $5.48 per thousand cubic feet in 2012. Average annual bitumen prices decreased 14 percent, from $62.56 per barrel in 2011 to $53.91 per barrel in 2012.

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(1) Thousands of barrels per day.

(2) Millions of cubic feet per day.

Greater Prudhoe Area

The Greater Prudhoe Area includes the Prudhoe Bay Field and five satellite fields, as well as the Greater Point McIntyre Area fields. Prudhoe Bay, the largest oil field on Alaska’s North Slope, is the site of a large waterflood and enhanced oil recovery operation, as well as a gas processing plant which processes natural gas for reinjection into the reservoir. Prudhoe Bay’s satellites are Aurora, Borealis, Polaris, Midnight Sun and Orion, while the Point McIntyre, Niakuk, Raven and Lisburne fields are part of the Greater Point McIntyre Area.

Greater Kuparuk Area

We operate the Greater Kuparuk Area, which is made up of the Kuparuk Field and four satellite fields: Tarn, Tabasco, Meltwater and West Sak. Kuparuk is located 40 miles west of Prudhoe Bay on Alaska’s North Slope. Field installations include three central production facilities that separate oil, natural gas and water, as well as a separate seawater treatment plant. The natural gas is either used for fuel or compressed for reinjection.

Western North Slope

On the Western North Slope, we operate the Colville River Unit, which includes the Alpine Field and three satellite fields: Nanuq, Fiord and Qannik. Alpine is located 34 miles west of Kuparuk. In October 2012, Alpine West CD5, a satellite field located west of Alpine in the National Petroleum Reserve—Alaska (NPRA), was sanctioned. Initial production is anticipated in late 2015, with net peak production estimated at 10 MBOED in 2016.

Cook Inlet Area

We operate the North Cook Inlet Unit, the Beluga River Unit, and the Kenai LNG Plant in the Cook Inlet Area. We have a 100 percent interest in the North Cook Inlet Unit and the Kenai LNG Plant, while we own 33.3 percent of the Beluga River Unit. Our share of production is sold to local utilities and is also used to supply feedstock and fuel to the Kenai LNG Plant.

The Kenai LNG Plant had historically supplied LNG to utility companies in Japan. Although we idled the plant in October 2012, we maintain the capability to operate it and are evaluating options for future use. The LNG export license will expire in March 2013.

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Point Thomson

We own a 5 percent interest in the Point Thomson Field, which is located approximately 60 miles east of Prudhoe Bay. An initial production system is anticipated to be online by 2016, which is estimated to send 400 net BOED of condensate through the Trans-Alaska Pipeline System (TAPS).

North Slope Natural Gas

In March 2012, we, along with Exxon Mobil Corporation, BP p.l.c. and TransCanada Corporation, announced we are working together on a plan aimed at commercializing North Slope natural gas resources through large-scale LNG exports from south-central Alaska. Planning and assessment is ongoing.

Exploration

In the February 2008 Outer Continental Shelf (OCS) Lease Sale 193, we successfully bid and were awarded 10-year-primary-term leases on 98 blocks in the Chukchi Sea. We plan to drill an exploration well on our Devil’s Paw prospect in 2014, subject to the outcome of pending litigation challenging Lease Sale 193 and the receipt of required regulatory permits.

Shark Tooth #1, an appraisal step-out well from the southwestern area of the Kuparuk Field, was spud in January 2012, and is being evaluated for further development potential. During 2013, we plan to drill one exploration well, Cassin, on the North Slope.

Transportation

We transport the petroleum liquids produced on the North Slope to south-central Alaska through an 800-mile pipeline that is part of TAPS. We have a 28.3 percent ownership interest in TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok Pipelines on the North Slope.

Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope production, using five company-owned double-hulled tankers in addition to chartering third-party vessels as necessary.

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Onshore

We hold 13.8 million net acres of onshore conventional and unconventional acreage in the Lower 48. Our unconventional holdings total 2.5 million net acres and include approximately 626,000 net acres in the Bakken; 227,000 net acres in the Eagle Ford; 194,000 net acres in Permian; 130,000 net acres in Niobrara; 900,000 net acres in the San Juan Basin; and nearly 430,000 net acres in other unconventional exploration plays. The majority of this acreage is either held by production or owned by the Company.

The majority of our 2012 onshore production originated from the San Juan Basin, Permian Basin, Eagle Ford, Bakken, Barnett, the Lobo Trend, Anadarko Basin and Bossier Trend. We also have operations in the Wind River Basin, East Texas, Rockies and northern and southern Louisiana. Onshore activities in 2012 were centered mostly on continued optimization and development of existing and emerging assets, with particular focus on areas with higher liquids production.

Exploration and development continued in our shale positions in the Eagle Ford, Bakken and Barnett. In the Eagle Ford, we drilled 211 exploration and development wells and connected 170 wells in 2012, achieving net peak production of over 100 MBOED in December 2012. In 2013, we plan to drill approximately 140 wells and connect approximately 200 wells. With continued investments, we expect long-term average production from the Eagle Ford will be approximately 140 MBOED by 2016.

The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, includes significant conventional gas production, which yields approximately 35 percent natural gas liquids, as well as the majority of our U.S. coalbed methane (CBM) production. We hold approximately 1.3 million acres of oil and gas leases by production in San Juan, where we continue to pursue

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conventional development opportunities. This includes approximately 900,000 net acres of lease rights, where we are advancing the assessment of the Mancos shale play.

In January 2013, we entered into an agreement to sell the majority of our properties in the Cedar Creek Anticline, comprising approximately 86,000 net acres in southwestern North Dakota and eastern Montana. The transaction is expected to close in the first quarter of 2013.

Gulf of Mexico

At year-end 2012, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one operated field and three fields operated by co-venturers, including:

Exploration

In the deepwater Gulf of Mexico, we held 1.7 million acres at December 31, 2012. In November 2012, we were the successful high bidder on 62 blocks in OCS Western Lease Sale 229, the majority of which have been awarded to date. We anticipate the remaining blocks will be awarded in the first quarter of 2013, which would increase our Gulf of Mexico position to 2.0 million net acres. In 2013, drilling continued on the partner-operated Coronado wildcat well and the Shenandoah appraisal well, both of which were spud in 2012. During the first half of 2013, drilling is expected to commence on the partner-operated Ardennes wildcat well, the Tiber appraisal well and a ConocoPhillips-operated wildcat well in the Miocene/Pliocene Thorn prospect. We also plan to participate in two-to-three additional non-operated wildcat wells in 2013.

In support of our intentions to grow our Gulf of Mexico exploration program, we secured access to an ultra deepwater drillship in 2012, which will provide rig availability for our operated drilling program beginning in 2014.

In 2012, we actively pursued the appraisal of our existing unconventional resource plays, including the Eagle Ford in South Texas, the Bakken in the Williston Basin, the Barnett in the Fort Worth Basin, the Niobrara play in the Denver-Julesburg Basin, the Avalon and Wolfcamp in the Permian Basin, and the Mancos in the San Juan Basin. During 2012, we acquired approximately 340,000 net additional acres in various resource plays across the Lower 48, which included the Avalon, Wolfcamp, Niobrara, and various exploration plays, further expanding our significant acreage position in Lower 48 shale plays to approximately 2.5 million net acres.

During 2012, we drilled a total of 20 unconventional test wells in the Avalon, Wolfcamp, Niobrara, Bakken Little Missouri, Lewis and Mancos plays. Drilling is expected to continue in 2013.

Transportation

Our 25 percent interest in the Rockies Express Pipeline (REX) was transferred to Phillips 66 as part of the separation. We retained the capacity rights and obligations to REX.

Facilities

Freeport LNG Terminal

We have a long-term agreement with Freeport LNG Development, L.P. to use 0.9 billion cubic feet per day of regasification capacity at Freeport’s 1.5-billion-cubic-feet-per-day LNG receiving terminal in Quintana, Texas.

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Market conditions currently favor the flow of LNG to European and Asian markets; therefore, our near- to mid-term utilization of the Freeport Terminal is expected to be limited to LNG storage and reload activities. We are responsible for monthly process-or-pay payments to Freeport irrespective of whether we utilize the terminal for regasification. The financial impact of these capacity underutilization payments is not expected to be material to our future earnings or cash flows.

Golden Pass LNG Terminal

We have a 12.4 percent ownership interest in the Golden Pass LNG Terminal and affiliated Golden Pass Pipeline. It is located adjacent to the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. The terminal became commercially operational in May 2011. We hold terminal and pipeline capacity for the receipt, storage and regasification of the LNG purchased from Qatargas 3 and the transportation of regasified LNG to interconnect with major interstate natural gas pipelines. Market conditions currently favor the flow of LNG to European and Asian markets; therefore, our near-to-mid-term utilization of the terminal is expected to be limited.

Phoenix Park Gas Processors Limited

We own a 39 percent interest in Phoenix Park Gas Processors Limited, which processes natural gas in Trinidad and markets natural gas liquids in the Caribbean, Central America and the U.S. Gulf Coast. Facilities include a 2-billion-cubic-feet-per-day gas processing plant and a 70,000 barrel-per-day natural gas liquids fractionator.

Other

Venezuela

In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010, and we anticipate an interim decision on key legal and factual issues in 2013. In a separate commercial arbitration from the Company’s ICSID claim discussed above, an International Chamber of Commerce (ICC) tribunal issued a decision in favor of the Company in September 2012, finding PDVSA owed $67 million for pre-expropriation breaches of the Petrozuata project agreements. In November 2012, based on the ICC tribunal ruling, PDVSA paid ConocoPhillips $68 million, including post-judgment interest, which resulted in a $61 million after-tax earnings increase. The Company also recognized additional income of $173 million after-tax associated with the reversal of a related contingent liability accrual.

Ecuador

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. On April 24, 2012, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on December 14, 2012, in favor of Burlington,

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finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase will take place to determine the damages owed to ConocoPhillips for Ecuador’s actions.

Peru

Exploration

We own a 45 percent operating interest in Blocks 123 and 129, covering nearly 1.6 million net acres. In October 2012, we announced our decision not to pursue further exploration activities in Blocks 123 and 129. This decision to withdraw is part of our strategic plan to optimize our portfolio of assets.

Western Canada

Our operations in western Canada are primarily comprised of three core development areas: Deep Basin, Kaybob and O’Chiese, which extend from central Alberta to northeastern British Columbia. We operate or have ownership interests in approximately 80 natural gas processing plants in the region, and, as of December 31, 2012, held leasehold rights in 5.9 million net acres in western Canada.

Oil Sands

We hold approximately 1.1 million net acres of land in the Athabasca Region of northeastern Alberta. Our bitumen resources in Canada are produced via an enhanced thermal oil recovery method called steam-assisted gravity drainage (SAGD), whereby steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and pumped to the surface for further processing.

The Surmont oil sands leases are located approximately 35 miles south of Fort McMurray, Alberta. Surmont is a 50/50 joint venture with Total S.A. Surmont Phase 2 construction began in 2010, with production startup targeted for 2015. Following startup, Surmont’s gross production capacity is estimated to be 150 MBOED, with net peak production of 65 MBOED anticipated by 2018.

We have a 50/50 heavy oil business venture with Cenovus Energy Inc., FCCL Partnership, a Canadian upstream general partnership. FCCL’s assets, operated by Cenovus, include the Foster Creek, Christina Lake and Narrows Lake SAGD bitumen developments.

Construction continued in 2012 on both the Foster Creek and Christina Lake properties. At Christina Lake, Phase D was completed and production came on stream in the third quarter of 2012. Phase D

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added 40 MBOED of gross production capacity, bringing total gross production capacity to 98 MBOED. Phase E is expected to be completed in 2013, with first production targeted for the second half of 2013, which will add another 40 MBOED of gross production capacity. Phase F was sanctioned in the fourth quarter of 2012, with production startup anticipated in 2016, which will add an additional 50 MBOED of gross production capacity.

At Foster Creek, construction progressed on Phases F, G and H, which are estimated to be completed in 2014, 2015 and 2016, respectively. These phases will add approximately 125 MBOED of gross production capacity. FCCL anticipates submitting an application for regulatory approval for an additional expansion, Phase J, in 2013.

Narrows Lake is a new oil sands development within the FCCL Partnership. In May 2012, FCCL received approval from the Alberta government to proceed with Narrows Lake. Narrows Lake Phase A was sanctioned in the fourth quarter of 2012, and initial production is anticipated in 2017.

Parsons Lake/Mackenzie Gas Project

We were involved with three other energy companies, as members of the Mackenzie Gas Project, on the development of the Mackenzie Valley Pipeline and gathering system, which was proposed to transport onshore gas production from the Mackenzie Delta in northern Canada to established markets in North America. We have a 75 percent interest in the Parsons Lake natural gas field, one of the primary fields in the Mackenzie Delta, which would anchor the pipeline development. Due to a continued decline in market conditions and lack of acceptable commercial terms, the project was suspended indefinitely in the first quarter of 2012. As a result, we recorded a $520 million after-tax impairment in 2012 for the carrying value of capitalized development costs and associated undeveloped leasehold costs.

Amauligak

We have a 53.8 percent operating interest in Amauligak, which lies approximately 31 miles offshore in shallow water in the Beaufort Sea. A range of development options are being evaluated.

Exploration

We hold exploration acreage in four areas of Canada: offshore eastern Canada, onshore western Canada, the Mackenzie Delta/Beaufort Sea Region and the Arctic Islands.

During 2012, we drilled unconventional test wells in the Duvernay and Montney plays. In 2013, exploration activities will continue in Duvernay, the Canol Shale in the Northwest Territories, Muskwa in the Horn River Basin and the Montney play. We also plan to continue delineating potential development opportunities in the oil sands.

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EUROPE

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. In 2012, operations in Europe contributed 17 percent of our worldwide liquids production and 13 percent of natural gas production.

The Greater Ekofisk Area, located approximately 200 miles offshore Stavanger, Norway in the North Sea, is comprised of four producing fields: Ekofisk, Eldfisk, Embla and Tor. Crude oil is exported to Teesside, England, and the natural gas is exported to Emden, Germany. The Ekofisk South and Eldfisk II developments continue, with production expected in the fourth quarters of 2013 and 2014, respectively.

The Alvheim development consists of a floating production, storage and offloading (FPSO) vessel and subsea installations. Produced crude oil is exported via shuttle tankers, and natural gas is transported to the United Kingdom via a pipeline to the Beryl-Sage system.

The Heidrun Field is located in the Norwegian Sea. Produced crude oil is transported to Mongstad in Norway and Tetney in the United Kingdom by double-hulled shuttle tankers. Part of the natural gas is transported and sold to buyers in Europe, while the remainder is used as feedstock in a methanol plant in Norway, in which we own an 18.3 percent interest.

We also have varying ownership interests in five other producing fields in the Norway sector of the North Sea and in the Norwegian Sea.

In the second quarter of 2012, we sold our Norway and U.K. interests in the Statfjord Field and associated satellites.

Exploration

During 2012, we completed the evaluation of available acreage for the 22 ^nd Licensing Round and submitted an application in December.

Transportation

We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil from Ekofisk to a crude oil stabilization and natural gas liquids processing facility in Teesside, England. In addition, we own a 1.9 percent interest in Norwegian Continental Shelf Gas Transportation (Gassled), which owns most of the Norwegian gas transportation infrastructure.

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In addition to our interest in the Britannia natural gas and condensate field, we own 50 percent of Britannia Operator Limited, the operator of the field. Condensate is delivered through the Forties Pipeline to an oil stabilization and processing plant near the Grangemouth Refinery in Scotland, while natural gas is transported through Britannia’s line to St. Fergus, Scotland. The Britannia satellite fields, Callanish and Brodgar, produce via subsea manifolds and pipelines linked to the Britannia platform.

J-Area is comprised of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. Development of the Jasmine Field continued during 2012, and we anticipate first production in the fourth quarter of 2013. Jasmine is estimated to achieve average net peak production of 37 MBOED in 2014.

We have various ownership interests in 18 producing gas fields in the Rotliegendes and Carboniferous areas of the Southern North Sea. Our interests in the East Irish Sea include the Millom, Dalton and Calder fields, which are operated on our behalf by a third party.

We own a 24 percent interest in the Clair Field, located in the Atlantic Margin. The development of Clair Ridge received government approval in October 2011, and initial production is estimated to occur in 2016.

We sold our interest in the Alba Field in the second quarter of 2012.

Exploration

We were awarded three licenses during 2012, one in the East Irish Sea and two in the Central Graben, North Sea. We approved the Greater Clair exploration and appraisal program in 2012 and plan to commence drilling in 2013.

Transportation

We have a 10 percent interest in the Interconnector Pipeline, which links the United Kingdom and Belgium and facilitates the marketing throughout Europe of natural gas produced in the United Kingdom. In January 2013, we entered into an agreement to sell our equity interest. The sale is expected to close in the first quarter of 2013.

We operate the Teesside oil and Theddlethorpe gas terminals in which we have 29.3 percent and 50 percent ownership interests, respectively. We also have a 100 percent ownership interest in the Rivers Gas Terminal, operated by a third party, in the United Kingdom.

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Poland

Exploration

We are participating in a shale gas venture in Poland. In the third quarter of 2012, we exercised our option to acquire a 70 percent interest in Lane Energy Poland and assumed operatorship for three western Baltic Basin concessions. Four wells have been drilled on these concessions, with further well tests and drilling planned for 2013. A 3-D seismic survey is also planned for the first quarter of 2013.

Greenland

Exploration

During 2012, we successfully completed a 2-D seismic survey in Block 7011/11 of the Qamut license in West Greenland and recovered stratigraphic cores which will guide the interpretation of this new data. In addition, we have completed the evaluation of available acreage in East Greenland.

ASIA PACIFIC AND MIDDLE EAST

The Asia Pacific and Middle East segment has exploration and production operations in China, Indonesia, Malaysia, Australia and the Timor Sea; producing operations in Qatar; and exploration activities in Bangladesh and Brunei. In 2012, operations in the Asia Pacific and Middle East segment contributed 13 percent of our worldwide liquids production and 28 percent of natural gas production.

Australia Pacific LNG

Australia Pacific LNG Pty Ltd (APLNG), our joint venture with Origin Energy and China Petrochemical Corporation (Sinopec), is focused on producing CBM from the Bowen and Surat basins in Queensland, Australia. Origin operates APLNG’s production and pipeline system, and we will operate the LNG facility. Natural gas is currently sold to domestic customers, while progress continues on the development of an LNG processing and export sales business. Once established, this will enhance our LNG position and serve as an additional LNG hub supplying Asia Pacific markets. Two initial 4.5-million-tonnes-per-year LNG trains have been sanctioned, with approximately 9,000 net wells ultimately envisioned to supply both the domestic gas market and the LNG development. The additional wells will be supported by expanded gas gathering systems, centralized gas processing and compression stations, and water treatment facilities, in addition to a new export pipeline from the gas fields to the LNG facilities.

During 2011, three significant milestones were achieved. First, the development received environmental approval from the Australian federal government. Second, definitive agreements were signed with Sinopec for the supply of up to 4.3 million tonnes of LNG per year for 20 years. The agreements also specified terms under which Sinopec subscribed for a 15 percent equity interest in APLNG, with both our ownership interest and Origin Energy’s ownership interest diluting from 50 percent to 42.5 percent. The Subscription Agreement was completed in August 2011. Third, a binding Heads of Agreement was signed with Japan-based Kansai Electric Power Co. Inc., for the sale of approximately 1 million tonnes of LNG per year for 20 years.

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In January 2012, APLNG and Sinopec signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million tonnes of LNG per year through 2035. This agreement, in combination with the Kansai Electric agreement, finalized the marketing of the second train. In July 2012, we sanctioned the development of the second 4.5-million-tonnes-per-year LNG production train. Start-up of the second train is expected to occur in the fourth quarter of 2015, with resulting LNG exports commencing shortly thereafter sold under the binding sales agreements to Sinopec and Kansai Electric. Upon sanctioning of the second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed to additional shares in APLNG, which increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin Energy’s ownership interest diluted from 42.5 percent to 37.5 percent.

APLNG executed project financing agreements for an $8.5 billion project finance facility during the third quarter of 2012 and began drawing on the financing in October 2012. Our reduced ownership interest, coupled with Sinopec’s $2.1 billion injection into APLNG associated with the dilution and APLNG’s successful placement of the $8.5 billion of project financing, will lower our future capital requirements to fund the project. We are evaluating opportunities to further reduce our ownership interest in APLNG. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility, which will be released upon meeting certain completion milestones.

For additional information, see Note 3—Variable Interest Entities (VIEs), Note 6—Investments, Loans and Long-Term Receivables, and Note 13—Guarantees, in the Notes to Consolidated Financial Statements.

Bayu-Undan

The Bayu-Undan gas condensate field is located in the Timor Sea Joint Petroleum Development Area between Timor-Leste and Australia. We also operate and own a 56.9 percent interest in the associated Darwin LNG Facility, located at Wickham Point, Darwin. Produced natural gas is used to supply the Darwin LNG Plant. In 2012, we sold 148 billion gross cubic feet of LNG to utility customers in Japan.

During the first half of 2013, the Bayu-Undan Phase 3 Development will focus on procuring long-lead items and securing contracts for a semi-submersible drilling rig. Final Investment Decision is expected in mid-2013 and will be followed by further detailed engineering and procurement activities. Drilling is anticipated to commence in the second quarter of 2014.

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax assessments. Between 2010 and 2012, ConocoPhillips has paid, under protest, tax assessments totaling approximately $227 million, which are primarily recorded in the “Investments and long-term receivables” line on our December 31, 2012, consolidated balance sheet. The arbitration will be conducted in Singapore under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste Government. The arbitration process is currently underway. Future impacts on our business are not known at this time.

Athena/Perseus

The Athena production license (WA-17-L) is located offshore Western Australia and contains part of the Perseus Field which straddles the boundary with WA-1-L, an adjoining license area. Natural gas is produced from these licenses.

Greater Sunrise

We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor Sea. Although the Sunrise Joint Venture and the governments of Australia and Timor-Leste are aligned with the objective to develop the Greater Sunrise Field, key challenges must be resolved before significant funding commitments can be made. These include gaining agreement between both governments and the joint venture on a development concept.

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Exploration

We operate three permits located in the Browse Basin, offshore northwest Australia. We own a 60 percent interest in two of the permits, WA-315-P and WA-398-P, and a 10 percent interest in WA-314-P. Phase I of the 2009/2010 drilling campaign resulted in discoveries in WA-315-P and WA-398-P. Phase II of the drilling campaign, expected to consist of a five-to-eight well program, commenced in 2012. The first well, Boreas-1, discovered hydrocarbons and was completed, plugged and abandoned in 2012. The second well, Zephyros-1, is currently being drilled and is expected to reach targeted depth in the first quarter of 2013.

In the Bonaparte Basin, offshore northern Australia, we operate and own interests in three permits, NT/RL5, NT/P69 and NT/P61. In 2012, we farmed-down our interest from 60 percent to 37.5 percent. A three-well appraisal program is expected to commence in 2014.

In September 2011, we executed a farm-in agreement to acquire a 75 percent working interest in four exploration permits: EP-443, EP-450, EP-451 and EP-456, which cover approximately 11 million gross acres in the Canning Basin of Western Australia. In 2012, our 75 percent interest in the permits was approved, and Phase I of a three-well drilling program commenced in the third quarter of 2012 with the drilling of the first well, Nicolay-1. The second well, Gibb-Maitland-1, was spud in December 2012. Upon completion of the Phase I drilling program, we will have the right to assume operatorship of the exploration permits.

We operate four production sharing contracts (PSCs) in Indonesia: the offshore South Natuna Sea Block B and three onshore PSCs, the Corridor Block and South Jambi “B”, both located in South Sumatra, and Warim in Papua. Our producing assets are primarily concentrated in two core areas: South Natuna Sea and onshore South Sumatra.

South Natuna Sea Block B

The offshore South Natuna Sea Block B PSC has 2 producing oil fields and 16 natural gas fields in various stages of development. Natural gas production is sold under international sales agreements to Malaysia and Singapore.

South Sumatra

The Corridor PSC consists of six oil fields and six natural gas fields in various stages of development. Natural gas is supplied from the Grissik and Suban gas processing plants to the Duri steamflood in central Sumatra and to markets in Singapore, Batam and West Java. The South Jambi “B” PSC includes three gas fields in various stages of development.

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Exploration

We own and operate an 80 percent interest in the Warim onshore exploration PSC in Papua. During 2012, we relinquished the Kuma and Arafura Sea offshore exploration PSCs.

Transportation

We are a 35 percent owner of a consortium company that has a 40 percent ownership in PT Transportasi Gas Indonesia, which owns and operates the Grissik to Duri and Grissik to Singapore natural gas pipelines.

The Peng Lai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05. Production from the Phase I development of the PL 19-3 Field began in 2002. The Phase II development includes six drilling and production platforms and an FPSO vessel used to accommodate production from all the fields.

In January 2012, we and the China National Offshore Oil Corp. (CNOOC) announced an agreement with China’s Ministry of Agriculture to resolve fishery-related issues in connection with two separate seepage incidents which occurred near the Peng Lai 19-3 Platforms B and C in 2011. Under this agreement, approximately $160 million was paid as compensation to settle private claims of potentially affected fishermen in relevant Bohai Bay communities, and public claims for alleged fishery damage. The agreement fulfills the objectives of the compensation fund we announced in September 2011. As part of this agreement, we have also designated approximately $16 million of our previously announced environmental fund to be used to improve fishery resources and for related projects.

In April 2012, we and CNOOC announced an agreement with China’s State Oceanic Administration (SOA) related to claims for possible impacts of the Peng Lai 19-3 seepage incidents on the Bohai Bay marine environment. Under this agreement, approximately $173 million will be paid to resolve claims, and approximately $18 million will be paid to support environmental initiatives focused on improving marine environment protection in Bohai Bay. Of the total $191 million, $86 million was paid in 2012.

We hold a 49 percent ownership interest in the Peng Lai fields.

The SOA required implementation of preventative measures to avoid recurrence of the incidents, in addition to the filing of an updated environmental impact assessment (EIA) and overall development plan (ODP) for approval. A revised ODP was submitted to China’s National Development and Reform Commission in November 2011, and a revised EIA was submitted to the SOA in February 2012. The EIA was approved in October 2012, and the ODP was approved in December 2012. In February 2013, we received notification from the SOA, which granted approval for a step-by-step resumption of normal production operations at the Peng Lai 19-3 Field in Bohai Bay.

The Panyu development, located in the South China Sea, is comprised of three oil fields: Panyu 4-2, Panyu 5-1 and Panyu 11-6. During 2012, a production platform was added to each of the Panyu 4-2 and Panyu 5-1 fields. Production from the new platforms began in September 2012.

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Exploration

In 2012, we entered into an agreement with Sinopec Southern Exploration Company to execute a joint study over the Qijiang Shale Gas Block, located in the Sichuan Basin. The Qijiang Shale Gas Block covers an area of 3,917 square kilometers. The study, which will be carried out over two years and includes seismic and drilling obligations, will be an important step in evaluating the potential for shale gas exploration in the area.

We own interests in four deepwater PSCs located off the eastern Malaysian state of Sabah: Block G, Block J, the Kebabangan (KBB) Cluster and SB-311. We have a 35 percent interest in Block G; 40 percent in Block J; 30 percent in KBB; and 40 percent in SB-311. First production from Gumusut, located in Block J, occurred in the fourth quarter of 2012. Production from a permanent, semi-submersible floating production and storage vessel is expected in late 2013, with estimated net annual peak production of 32 MBOED anticipated in 2014. The development of the KBB gas field commenced in 2011, with first production anticipated in late 2014. Estimated net annual peak production from KBB of 29 MBOED is expected in 2015. Development of the Siakap North-Petai oil field began in 2012, and first production is expected in late 2013. The Malikai oil field, sanctioned in the fourth quarter of 2012, is the fourth field under development. First production is anticipated in early 2017.

Exploration

In December 2012, we were formally awarded operatorship of exploration block SB-311, offshore Sabah. A two-well drilling program is planned for this block, and we expect to complete seismic reprocessing and acquisition in 2013.

Vietnam

We sold our Vietnam business in the first quarter of 2012. Net production averaged 3 MBOED in 2012.

Bangladesh

Exploration

In 2009, we were formally awarded two deepwater blocks in the Bay of Bengal, offshore Bangladesh. We received government approval of the PSC terms in June 2011 and hold 100 percent interests in Blocks 10 and 11. In 2012, we performed 2-D seismic activities and are currently evaluating the results.

Brunei

Exploration

We have a 6.25 percent working interest in Block CA-2. Two exploration wells were expensed as dry holes in 2011. Exploration activities continued during 2012, and we plan to drill a third well in 2013.

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Qatargas 3 (QG3) is an integrated development jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). QG3 is comprised of upstream natural gas production facilities to produce approximately 1.4 billion gross cubic feet per day of natural gas from Qatar’s North Field over a 25 year life. It also includes a 7.8-million-gross-tonnes-per-year LNG facility, from which LNG is shipped in leased LNG carriers destined for sale globally. First gas production was achieved in October 2010, and we achieved peak production during 2011.

QG3 executed the development of the onshore and offshore assets as a single integrated development with Qatargas 4 (QG4), a joint venture between Qatar Petroleum and Royal Dutch Shell plc. This included the joint development of offshore facilities situated in a common offshore block in the North Field, as well as the construction of two identical LNG process trains and associated gas treating facilities for both the QG3 and QG4 joint ventures. Production from the LNG trains and associated facilities are combined and shared.

OTHER INTERNATIONAL

The Other International segment includes exploration and producing operations in Libya and Russia, as well as exploration activities in Angola and the Caspian Sea. In 2012, we agreed to sell our Nigerian and Algerian businesses and our interest in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement (Kashagan). As such, results of these operations have been reclassified to discontinued operations for all periods presented. During 2012, operations in Other International contributed 6 percent of our worldwide liquids production.

The Waha Concession consists of multiple concessions and encompasses nearly 13 million gross acres in the Sirte Basin. Our production operations in Libya and related oil exports were temporarily suspended in 2011 during Libya’s period of civil unrest. Production restarted in late 2011 and reached 49 MBOED in November 2012.

Exploration

We participated in an exploration appraisal program within the Waha Concession in 2012 and are currently evaluating results. We drilled three appraisal wells during 2012 and completed one exploration well in early 2013.

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NMNG

We sold our interest in NMNG in the third quarter of 2012.

Polar Lights

Polar Lights Company is an entity which has developed several fields in the Timan-Pechora Basin in northern Russia.

Angola

Exploration

Effective January 1, 2012, we entered into two PSCs with Angola’s national oil company. We have a 30 percent operating interest in Blocks 36 and 37, both of which are located in Angola’s subsalt play trend. In 2012, we acquired 3-D seismic data for both ultra-deepwater blocks and are currently evaluating the data. The first wildcat well is expected to be spud in 2014.

Kazakhstan

Transportation

The Baku-Tbilisi-Ceyhan (BTC) Pipeline transports crude oil from the Caspian Region through Azerbaijan, Georgia and Turkey for tanker loadings at the port of Ceyhan. We have a 2.5 percent interest in BTC.

Exploration

We disposed of our interest in the N Block, located offshore Kazakhstan, in January 2013.

*Reclassified to discontinued operations.

We have an interest in four onshore Oil Mining Leases (OMLs). Natural gas is sourced from our proved reserves in the OMLs and provides fuel for a 480-megawatt gas-fired power plant in Kwale, Nigeria. We have a 20 percent interest in this power plant, which supplies electricity to Nigeria’s national electricity supplier. In 2012, the plant consumed 12 million net cubic feet per day of natural gas.

We have a 17 percent equity interest in Brass LNG Limited, which plans to construct an LNG facility in the Niger Delta.

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In December 2012, we entered into an agreement to sell our entire Nigerian business. The transaction is expected to close by mid-2013.

*Reclassified to discontinued operations.

Our activities in Algeria are centered around the following fields in Block 405a: the Menzel Lejmat North Fields (MLN), the Ourhoud Field and the EMK Field. Crude oil production from MLN and Ourhoud is transported to northern Algerian ports where it is sold. The development of the EMK Field, in which we own a 16.9 percent interest, was sanctioned in 2009. Startup is anticipated in mid-2013.

In December 2012, we entered into an agreement to sell our entire Algerian business. The transaction is expected to close by mid-2013.

Kazakhstan

In the Caspian Sea, we have an 8.4 percent interest in Kashagan. In November 2012, we announced our intention to sell our entire interest in Kashagan. The transaction is expected to close by mid-2013, subject to customary governmental approvals.

LUKOIL INVESTMENT

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.

OTHER

Marketing Activities

Our Commercial organization manages our worldwide commodity portfolio, which mainly includes natural gas, crude oil, bitumen, natural gas liquids and LNG. Marketing activities are performed through offices in the United States, Canada, Europe and Asia. In marketing our production, we attempt to minimize flow disruptions, maximize realized prices and manage credit-risk exposure. Commodity sales are generally made at prevailing market prices at the time of sale. We also purchase third-party volumes to better position the Company to fully utilize transportation and storage capacity and satisfy customer demand.

Natural Gas

Our natural gas production, along with third-party purchased gas, is marketed in the United States, Canada, Europe and Asia. Our natural gas is sold to a diverse client portfolio which includes local distribution companies; gas and power utilities; large industrials; independent, integrated or state-owned oil and gas companies; as well as marketing companies. To reduce our market exposure and credit risk, we also transport natural gas via firm and interruptible transportation agreements to major market hubs.

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Crude Oil, Bitumen and Natural Gas Liquids

Our crude oil, bitumen and natural gas liquids revenues are derived from production in the United States, Canada, Australia, Asia, Africa, China and Europe. These commodities are primarily sold under contracts with prices based on market indices, adjusted for location, quality and transportation.

Spill Containment

Marine Well Containment Company

We are a founding member of the Marine Well Containment Company (MWCC), a non-profit organization formed in 2010 which provides well containment equipment and technology in the deepwater U.S. Gulf of Mexico. In 2011, MWCC launched an interim containment system designed to improve containment response capabilities in the event of an underwater well control incident. In 2012, MWCC and the U.S. Bureau of Safety and Environmental Enforcement announced the successful demonstration of the industry’s ability to respond to a deepwater well control incident in the U.S. Gulf of Mexico. MWCC is advancing this capability and is currently developing an expanded containment system with significantly increased capacity. The expanded containment system is expected to be available in 2013.

Subsea Well Response Project

In 2011, we, along with eight leading oil and gas companies, launched the Subsea Well Response Project (SWRP), an initiative designed to enhance the industry’s capability to respond to international subsea well control incidents. In 2012, SWRP, a non-profit organization based in Stavanger, Norway, partnered with Oil Spill Response Limited, a non-profit organization in the United Kingdom, in order to develop integrated intervention systems which are more widely available to the industry. This complements the work being undertaken in the United States by MWCC and also in the United Kingdom by the Oil Spill Prevention and Response Advisory Group (OSPRAG), enhancing our global well response capabilities. We are also a participant in OSPRAG.

LNG Technology

Our Optimized Cascade ^® LNG liquefaction technology business continues to grow with the demand for new LNG plants. The technology has been applied in 10 LNG trains around the world, with 10 more under construction.

RESERVES

We have not filed any information with any other federal authority or agency with respect to our estimated total proved reserves at December 31, 2012. No difference exists between our estimated total proved reserves for year-end 2011 and year-end 2010, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2012.

DELIVERY COMMITMENTS

We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our Commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 4 trillion cubic feet of natural gas, including approximately 600 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 80 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2028. We expect to fulfill the majority of these delivery commitments with proved developed reserves. In addition, we anticipate using proved undeveloped reserves and spot market purchases to fulfill these remaining commitments. See the disclosure on “Proved Undeveloped Reserves” in the “Oil and Gas Operations” section following the Notes to Consolidated Financial Statements, for information on the development of proved undeveloped reserves.

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COMPETITION

We compete with private, public and state-owned companies in all facets of the E&P business. Some of our competitors are larger and have greater resources. Each of our segments is highly competitive, with no single competitor, or small group of competitors, dominating.

We compete with numerous other companies in the industry, including state-owned companies, to locate and obtain new sources of supply and to produce oil, bitumen, natural gas liquids and natural gas in an efficient, cost-effective manner. Based on publicly available year-end 2011 reserves statistics, we had the seventh-largest total of worldwide proved reserves of nongovernment-controlled companies. We deliver our production into the worldwide commodity markets. Principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; economic analysis in connection with portfolio management; and efficiently operating oil and gas producing properties.

GENERAL

At the end of 2012, we held a total of 784 active patents in 54 countries worldwide, including 319 active U.S. patents. During 2012, we received 15 patents in the United States and 47 foreign patents. Our products and processes generated licensing revenues of $124 million in 2012. The overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession.

Company-sponsored research and development activities charged against earnings were $221 million, $193 million and $172 million in 2012, 2011 and 2010, respectively.

Our Health, Safety and Environment (HSE) organization provides tools and support to our business units and staff groups to help them ensure consistent health, safety and environmental excellence. In support of the goal of zero incidents, we have implemented an HSE Excellence process, which enables business units to measure their performance and compliance with our HSE Management System requirements, identify gaps, and develop improvement plans. Assessments are conducted annually to capture progress and set new targets. We are also committed to continuously improving process safety and preventing releases of hazardous materials.

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 58 through 62 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2012 and those expected for 2013 and 2014.

Website Access to SEC Reports

Our Internet website address is www.conocophillips.com . Information contained on our Internet website is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the U.S. Securities and Exchange Commission (SEC). Alternatively, you may access these reports at the SEC’s website at www.sec.gov .

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