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 asset disposition program, in the fourth quarter of 2013, we completed the sale of our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and the sale of our Algeria business, and we have agreements to sell our Nigeria business. Results of operations related to Phillips 66, Kashagan, Algeria and Nigeria have been classified as discontinued operations in all periods presented in this Annual Report on Form 10-K. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Headquartered in Houston, Texas, we have operations and activities in 27 countries. Our key focus areas include safely operating producing assets, executing major developments and exploring for new resources in promising areas. Our portfolio includes resource-rich North American shale and oil sands assets; lower-risk legacy assets in North America, Europe, Asia and Australia; several major international developments; and a growing inventory of global conventional and unconventional exploration prospects.

At December 31, 2013, ConocoPhillips employed approximately 18,400 people worldwide.

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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, 2013, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

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:

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 83 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 following summary reserves table.

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Total production from continuing operations, including our share of equity affiliates, for 2013 averaged 1,502 thousand barrels of oil equivalent per day (MBOED), a 2 percent decrease compared with 1,527 MBOED in 2012. The decrease was mainly due to normal field decline, asset dispositions, shut-in Libya production, due to the closure of the Es Sider crude oil export terminal, and higher unplanned downtime. These decreases were partially offset by new production from major developments, mainly from shale plays in the Lower 48, the ramp-up of production from new phases at Christina Lake in Canada, and early production in Malaysia; higher production in China; and increased conventional drilling and well performance, mostly in the Lower 48, western Canada and Norway. Adjusted for dispositions, downtime and the impact from the closure of the Es Sider Terminal in Libya, production grew by 30 MBOED, or 2 percent, compared with 2012.

Our total realized price from continuing operations remained relatively flat in 2013, from $67.68 per BOE in 2012, compared with $67.62 per BOE in 2013. Our worldwide annual average crude oil sales price from continuing operations decreased 2 percent in 2013, from $105.72 per barrel in 2012 to $103.32 per barrel in 2013. Additionally, our worldwide average annual natural gas liquids prices from continuing operations decreased 11 percent, from $46.36 per barrel in 2012 to $41.42 per barrel in 2013. Our average annual worldwide natural gas sales price from continuing operations increased 11 percent, from $5.48 per thousand cubic feet in 2012 to $6.11 per thousand cubic feet in 2013. Average annual bitumen prices decreased 1 percent, from $53.91 per barrel in 2012 to $53.27 per barrel in 2013.

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ALASKA

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. We are the largest crude oil and natural gas producer in Alaska and have major ownership interests in two of North America’s largest oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk. We also have a significant operating interest in the Alpine Field, located on the Western North Slope. Additionally, we are one of Alaska’s largest owners of state and federal exploration leases, with approximately 0.9 million net undeveloped acres at year-end 2013. Approximately 0.5 million of these acres are located in the National Petroleum Reserve—Alaska (NPRA) and 0.3 million are located in the Chukchi Sea. In 2013, Alaska operations contributed 23 percent of our worldwide liquids production and 1 percent of our natural gas production.

* Thousands of barrels per day.

** 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 consists of the Kuparuk Field and four satellite fields: Tarn, Tabasco, Meltwater and West Sak. Kuparuk is located 40 miles west of Prudhoe Bay. Field installations include three central production facilities which separate oil, natural gas and water, as well as a separate seawater treatment plant. New rotary-drilled wells and sidetracks from existing well bores utilizing coiled-tubing drilling are the primary means for development drilling at Kuparuk.

The successful Shark Tooth delineation well extended the known Kuparuk accumulation to the southwestern area of the Kuparuk Field. As a result, plans for the future development of Drill Site 2S are progressing, with project sanction targeted for late 2014 and first production estimated in late 2015.

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. Construction is progressing on Alpine West CD5, a drill site to access the western extension of the Alpine reservoir, in the NPRA. Initial production is anticipated in late 2015, with net peak production estimated at 10 MBOED in 2016.

The Greater Mooses Tooth Unit, the first unit established entirely within the NPRA, was formed in 2008. We are progressing development planning for the Greater Mooses Tooth #1 (GMT1) drill site in the Greater Mooses Tooth Unit. We filed permitting applications for GMT1 in July 2013, and project sanction is targeted for late 2014. GMT1 is planned to be connected by road to the CD5 drill site, and production will be

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transported by pipeline to the existing Alpine facilities for processing. Construction is estimated to begin in 2016, with first production anticipated in late 2017. We are evaluating further exploration and development potential in the NPRA.

Cook Inlet Area

We operate the North Cook Inlet Unit, the Beluga River Unit, and the Kenai LNG Facility in the Cook Inlet Area. We have a 100 percent interest in the North Cook Inlet Unit and the Kenai LNG Facility, while we own 33.3 percent of the Beluga River Unit. Both units produce natural gas, and our share of production is currently sold to local utilities.

The Kenai LNG Facility includes a 1.3 million-tons-per-year capacity plant, which historically manufactured LNG for sale to utility companies in Japan, as well as docking and loading facilities, which enable the LNG to be transported by tanker. Although our LNG export license expired in March 2013, the plant is operational and in stand-by mode, maintaining the flexibility to resume limited operations. Due to a change in market conditions, including additional gas supplies, we submitted applications in December 2013 to the U.S. Department of Energy to resume LNG exports from the Kenai LNG Facility.

Point Thomson

We own a 5 percent interest in the Point Thomson Unit, 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).

More Alaska Production Act (MAPA)

Following the April 2013 enactment of revised oil tax legislation, MAPA, we have increased our exploration and development investments and activities on the North Slope by adding rigs and progressing new development opportunities. We will continue to work with co-owners to identify additional opportunities to increase our investments in Alaska.

Alaska LNG (AKLNG)

During 2012, we, along with affiliates of Exxon Mobil Corporation, BP p.l.c. and TransCanada Corporation (collectively, the “AKLNG co-venturers”), began evaluating a potential LNG project which would export and liquefy natural gas from Alaska’s North Slope and deliver it to market. The AKLNG Project concept is an integrated LNG project consisting of a liquefaction plant, including marine terminal facilities and auxiliary marine vessels, located in south-central Alaska; a natural gas treatment plant, located on the North Slope; and an estimated 800-mile natural gas pipeline, which would connect the two plants.

In October 2013, the AKLNG co-venturers selected the Nikiski area on the Kenai Peninsula as the lead site for the proposed AKLNG natural gas liquefaction plant and terminal. On January 14, 2014, the AKLNG co-venturers, the Commissioners of the Alaska Departments of Revenue and Natural Resources, and the Alaska Gasline Development Corporation, a state-owned corporation, signed a Heads of Agreement (HOA) for the AKLNG Project. The HOA provides a roadmap of how the parties intend to progress the project, including proposed terms for participation by the State of Alaska as an equity owner, proposed fiscal and regulatory terms, and proposed terms for expansion of project components. One of the initial steps in the HOA is enactment of general legislation by the State of Alaska, as well as further commercial agreements, which would be subject to approval by the Alaska legislature. Significant engineering, technical, regulatory, fiscal, commercial and permitting issues would need to be resolved prior to a final investment decision on the potential 17 million-tons-per-year, $45 billion to $65 billion (gross) project. Following the enabling legislation, we anticipate commencing preliminary front-end engineering and development, currently estimated in the second quarter of 2014.

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Exploration

In April 2013, we suspended our plans to drill an exploration well in the Chukchi Sea in 2014, in light of the uncertainties of evolving federal regulatory requirements and operational permitting standards. Once these requirements are clarified and better defined, we will re-evaluate plans for drilling in the Chukchi Sea.

In 2013, we drilled and flow-tested a new discovery at the Cassin prospect, located in the Bear Tooth Unit in the northeast NPRA, and we also tested the Moraine play on the western flank of the Kuparuk Field. The results for both wells are currently under evaluation. Additionally, we plan to drill two exploration wells within the Greater Mooses Tooth Unit in 2014: the Rendezvous 3, which is currently drilling, and Flattop-1, which is expected to be spud later in the first quarter of 2014.

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 29.1 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 and chartering third-party vessels, as necessary. The tankers deliver oil from Valdez, Alaska, to refineries on the west coast of the United States.

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LOWER 48 AND LATIN AMERICA

The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states, as well as exploration activities in the Gulf of Mexico and Colombia. As a result of increasing shale opportunities and a low natural gas price environment, we have directed our investments toward high-margin, liquids-rich plays, predominantly in the Lower 48.

Onshore

We hold 13.1 million net acres of onshore conventional and unconventional acreage in the Lower 48, the majority of which is either held by production or owned by the Company. Our unconventional holdings total approximately 2.7 million net acres in the following areas:

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The majority of our 2013 onshore production originated from San Juan, Eagle Ford, Permian, Bakken, Anadarko, Lobo and Barnett. Onshore activities in 2013 were centered mostly on continued development and optimization of emerging and existing assets, with an emphasis on areas with higher-margin, liquids-rich production, particularly in growing unconventional plays. Our major focus areas in 2013 included the following:

Gulf of Mexico

At year-end 2013, 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 added approximately 430,000 net acres to our position in 2013, bringing our total acreage position to 2.1 million acres at December 31, 2013. Since 2011, we have nearly doubled our acreage footprint in the deepwater Gulf of Mexico and currently rank in the top five deepwater leaseholders. In 2013, we announced two new oil discoveries in the deepwater Lower Tertiary play at Coronado and Gila, adding to the existing Shenandoah and Tiber discoveries made in 2009.

We own a 30 percent working interest in the Shenandoah discovery. The results of the Shenandoah appraisal well were announced in 2013 and confirmed Shenandoah as a significant oil discovery. The well encountered more than 1,000 feet of net pay in high-quality, Lower Tertiary-aged reservoirs. We plan to participate in further appraisal of Shenandoah in 2014. The Coronado exploration well encountered more than 400 feet of net pay and will require further appraisal. We hold a 35 percent working interest in Coronado. In 2013, we acquired a 20 percent interest in the Gila Prospect, located

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in the Keathley Canyon section of the Gulf of Mexico. The Gila exploration well was announced as a discovery in 2013 and is expected to be appraised in 2014.

Ongoing drilling activities at the end of 2013 included a Tiber appraisal well, in which we own an 18 percent working interest, a Coronado appraisal well and the Deep Nansen exploration well. We hold a 12.5 percent interest in the Deep Nansen well. We plan to evaluate the results of these wells in the first half of 2014.

The nonoperated Ardennes wildcat well and the ConocoPhillips-operated Thorn wildcat well were declared dry holes in 2013.

In support of our intentions to grow our Gulf of Mexico exploration program, we secured access to two new-build deepwater drillships, which we anticipate will be delivered to the Gulf of Mexico in 2014 and 2015. The drillships will provide rig availability for our operated drilling program.

In 2013, we actively pursued the exploration and appraisal of our existing unconventional resource plays, including the Eagle Ford in the Western Gulf Basin, the Bakken in the Williston Basin, the Barnett in the Fort Worth Basin, the Niobrara play in the Denver-Julesburg Basin, Wolfcamp and Bone Springs in the Delaware Basin, Wolfcamp in the Midland Basin, and the Mancos in the San Juan Basin. During 2013, we acquired approximately 61,000 net additional acres in various resource plays across the Lower 48, which included the Eagle Ford, Niobrara and Permian plays, further expanding our significant acreage position in Lower 48 shale plays to approximately 2.7 million net acres.

During 2013, we drilled a total of 25 unconventional wells in the Niobrara, Bone Springs and Wolfcamp plays. In 2014, we will continue to actively explore and appraise unconventional plays in the Lower 48, with a focus on Bone Springs, Wolfcamp and Niobrara. We will also continue to assess new opportunities in unconventional plays.

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. In July 2013, we agreed with Freeport LNG to terminate this agreement, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. Upon satisfaction of these conditions, currently expected to occur in the second half of 2014, we will pay Freeport LNG a termination fee of approximately $600 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, will result in a one-time net cash outflow of approximately $80 million for us. When the agreement becomes effective, we also expect to recognize an after-tax charge to earnings of approximately $540 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero. As a result of this transaction, we anticipate saving approximately $50 to $60 million per year in operating costs over the next 19 years. For additional information, see Note 4—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

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.

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Other

Asset Dispositions

During 2013, we sold the majority of our producing zones in the Cedar Creek Anticline, located in southwestern North Dakota and eastern Montana; certain properties located in southwest Louisiana; and our 39 percent equity interest in Phoenix Park Gas Processors Limited, located in Trinidad and Tobago. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Colombia

Unconventional Exploration

During 2013, we entered into a farm-in agreement with Canacol Energy Ltd. to acquire a 70 percent working interest for deep rights in the Santa Isabel Block in the Middle Magdalena Basin, which covers approximately 71,000 net acres. The first exploration well did not reach our planned La Luna Shale target and was expensed. Additional seismic acquisition and processing will continue in 2014. Additionally, we executed farm-in agreements to acquire 30 percent working interests in three blocks in the Middle Magdalena Basin, which cover approximately 116,000 net acres.

Venezuela

In September 2013, the World Bank’s International Centre for Settlement of Investment Disputes (ICSID) arbitration tribunal ruled Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in the Petrozuata and Hamaca heavy crude oil projects and the offshore Corocoro development project in June 2007. A separate arbitration phase will proceed to determine the amount of damages owed to ConocoPhillips for Venezuela’s actions. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Ecuador

In December 2012, an ICSID tribunal issued a decision on liability in favor of Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, 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 is now proceeding to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

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Western Canada

Our operations in western Canada primarily consist of three core development areas: Deep Basin, Kaybob and Clearwater, 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, 2013, held leasehold rights in 5.7 million net acres in western Canada.

Oil Sands

We hold approximately 0.9 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 peak production 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. FCCL continues to progress expansion plans which would potentially increase total gross production capacity to approximately 750 MBOED.

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Amauligak

We have a 55 percent operating interest in the Amauligak discovery, which lies approximately 30 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. Our primary exploration focus is on liquids-rich unconventional plays in Alberta, British Columbia and the Northwest Territories.

We hold approximately 0.7 million net acres in the emerging Montney, Muskwa, Duvernay and Canol unconventional plays in Alberta, northeastern British Columbia and the Northwest Territories. During 2013, we drilled unconventional test wells in the Duvernay, located in Alberta; the Canol shale, located in the Northwest Territories; and the Montney play, which extends from British Columbia into Alberta. In 2014, exploration activities will continue in Duvernay, Canol and Montney. We also plan to continue delineating potential development opportunities in the oil sands.

Asset Dispositions

During 2013, we sold our Clyden undeveloped oil sands leasehold. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

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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 2013, operations in Europe contributed 14 percent of our worldwide liquids production and 11 percent of natural gas production.

The Greater Ekofisk Area is located approximately 200 miles offshore Stavanger, Norway in the North Sea, and comprises four producing fields: Ekofisk, Eldfisk, Embla and Tor. Crude oil is exported to Teesside, England, and the natural gas is exported to Emden, Germany. In October 2013, we achieved first oil production from Ekofisk South, a development which includes the planned drilling of 35 new production and eight water injection wells. At year-end 2013, four production wells and the eight water injection wells had been drilled. A second development, Eldfisk II, is scheduled to start up by early 2015. Ekofisk South, along with Eldfisk II and other developments offshore Norway, are expected to add approximately 60 MBOED of net production within the next five years.

The Alvheim development is located in the northern part of the North Sea and 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 currently injected into the reservoir for optimization of crude oil production, 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, including the Aasta Hansteen development, a gas discovery with first gas scheduled for late 2017.

Exploration

During 2013, we participated in five nonoperated wells, of which three were discoveries. Also in 2013, we were awarded four new licenses in the 22 ^nd Licencing Round in the Norwegian Barents Sea: PL718, PL720, PL723 and PL615B. We plan to participate in two nonoperated wells in the Barents Sea in 2014. In January 2014, we were awarded one operatorship and an interest in one partnership license in the Predefined Areas gas licensing round for mature areas.

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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Britannia is one of the largest natural gas and condensate fields in the North Sea. In addition to our interest in the Britannia 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. A new mono-column design compression facility for the Britannia Platform is estimated to come on line in 2014 and increase Britannia’s natural gas production by approximately 90 MMCFD.

The J-Area consists of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. Jasmine was discovered in 2006, and first production commenced in November 2013. The Jasmine development includes a 24-slot wellhead platform with a bridge-linked accommodation and utilities platform, a six-mile, 16-inch multi-phase pipeline bundle, and a riser and processing platform bridge-linked to the existing Judy Platform. The field is a high-pressure, high-temperature gas condensate reservoir located approximately six miles west of the Judy Platform. Jasmine is estimated to achieve average net production of 30 MBOED in 2014.

We have various ownership interests in 19 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. Clair Ridge is the second phase of development for the Clair Field and is comprised of a 36-slot drilling and production facility with a bridge-linked accommodation and utilities platform. The new facilities will tie into existing oil and gas export pipelines to the Shetland Islands. Initial production for Clair Ridge is targeted for 2016.

Exploration

During 2013, we participated in two operated wells, Lacewing and Romeo, and three nonoperated wells in the Clair Field: HEXA, Segment 0 and Segment 5. The Lacewing well was deemed sub-commercial. All of the wells in the Greater Clair area were discoveries and are currently undergoing evaluation. The Romeo well is currently drilling and will be evaluated during 2014.

During 2013, we were awarded four licenses: three licenses in the Central Graben area of the North Sea, and one license in the Greater Clair area.

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Transportation

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. A project to replace the Acid Gas Plant at the Rivers Gas Terminal was completed in early 2014.

Asset Dispositions

We sold our 10 percent equity interest in the Interconnector Pipeline in the first quarter of 2013.

Poland

Exploration

We are participating in a shale gas venture in Poland and own a 70 percent equity interest in Lane Energy Poland. We operate three western Baltic Basin concessions, which encompass approximately 500,000 gross acres. Four wells have been drilled on these concessions, and further well tests and drilling are planned in 2014.

Greenland

Exploration

During 2013, we were awarded one non-operated license, Block 6, in the northeast area of Greenland.

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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 2013, operations in the Asia Pacific and Middle East segment contributed 13 percent of our worldwide liquids production and 30 percent of natural gas production.

Australia Pacific LNG

Australia Pacific LNG Pty Ltd (APLNG), our joint venture with Origin Energy Limited and China Petrochemical Corporation (Sinopec), is focused on producing CBM from the Bowen and Surat basins in Queensland, Australia, and converting the CBM into LNG. Natural gas is currently sold to domestic customers, while progress continues on the development of the LNG processing and export sales business. Origin operates APLNG’s upstream production and pipeline system, and we will operate the downstream LNG facility, located on Curtis Island near Gladstone, Queensland.

Two fully subscribed 4.5-million-tonnes-per-year LNG trains have been sanctioned. Approximately 3,900 net wells are ultimately envisioned to supply both the domestic gas market and the LNG sales contracts. The wells will be supported by gathering systems, central gas processing and compression stations, water treatment facilities, and a new export pipeline connecting the gas fields to the LNG facilities. First LNG is expected in mid-2015, under a sales agreement with Sinopec for up to 4.3 million metric tonnes of LNG per year for 20 years. Start-up of the second LNG train is expected to occur six-to-nine months following the startup of Train 1, under sales agreements with Sinopec and Japan-based Kansai Electric Power Co., Inc. The resulting LNG exports from Train 2 will commence shortly thereafter. Sinopec has agreed to purchase an additional 3.3 million metric tonnes of LNG per year through 2035, and Kansai has agreed to purchase approximately 1 million metric tonnes of LNG per year for 20 years.

In May 2012, APLNG executed project financing agreements for an $8.5 billion project finance facility and began drawing on the financing in October 2012. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility. Our guarantee of the project financing will be released upon meeting certain completion tests with milestones.

For additional information, see Note 4—Variable Interest Entities (VIEs), Note 7—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.

The Bayu-Undan natural gas recycle facility processes wet gas; separates, stores and offloads condensate, propane and butane; and re-injects dry gas back into the reservoir. In addition, a 500-kilometer natural gas

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pipeline connects the facility to the 3.5-million-tonnes-per-year capacity Darwin LNG Facility. Produced natural gas is piped to the Darwin LNG Plant, where it is converted into LNG before being transported to international markets. In 2013, we sold 167 billion gross cubic feet of LNG to utility customers in Japan.

The Bayu-Undan Phase Three Development was sanctioned in the third quarter of 2013, with development drilling anticipated to commence in the third quarter of 2014 and initial production estimated in the second quarter of 2015. The development will consist of two standalone, subsea horizontal wells tied back to the existing drilling, production, and processing (DPP) platform. In 2013, we secured a semi-submersible drilling rig, procured long-lead items and commenced planning and detailed engineering for subsea and DPP topsides installation. Planning and engineering activities will continue through 2014. The two wells are expected to produce over three to five years, with estimated average production of 150 MMCFD.

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. The arbitration process is currently underway. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

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. In May 2013, the Timor-Leste Government referred a dispute with the Australian Government relating to the treaty on Certain Maritime Arrangements in the Timor Sea (CMATS) to international arbitration. The CMATS arbitration does not directly impact our underlying interest in Sunrise; however, key challenges must be resolved before further commercial and technical work continues.

Exploration

We operate three permits in the Browse Basin, offshore northwest Australia. In 2013, we reduced our interests in two permits in the Greater Poseidon Area, WA-315-P and WA-398-P, from 60 percent to 40 percent. We have a 10 percent interest in WA-314-P, which is outside the Greater Poseidon Area. Phase I of the 2009/2010 Browse Basin drilling campaign resulted in discoveries in the Greater Poseidon Area: Poseidon-1, Poseidon-2 and Kronos-1. Phase II of the drilling campaign consists of six wells and commenced in 2012. The first two wells, Boreas-1 and Zephyros-1, discovered hydrocarbons and were completed, plugged and abandoned in 2012. The third well, Proteus-1, discovered hydrocarbons and was plugged and abandoned in 2013. The three wells were drilled in the Greater Poseidon Area. The fourth well, Grace-1, was drilled to satisfy a Year-5 permit obligation for WA-314-P. The Grace-1 was spud in late 2013, reached total depth in early 2014 and was declared a dry hole. The outcome does not affect our view of the overall Greater Poseidon Project.

In the Bonaparte Basin, offshore northern Australia, we operate the NT/RL5 and NT/RL6 permits. Our ownership interest in each of the permits is 37.5 percent. A three-well appraisal program is expected to commence in 2014 to further evaluate the field’s potential.

In 2013, we reduced our working interest in four exploration permits within the Canning Basin of Western Australia from 75 percent to 46 percent. These permits cover approximately 11 million gross acres. Phase I of a three-well drilling program commenced in 2012 with the drilling of the Nicolay-1 and the Gibb-Maitland-1 wells. Both were written off as dry holes in 2013. Phase I drilling is expected to resume in the second half of 2014.

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Asset Dispositions

During 2013, we sold 20 percent of our working interest in the Greater Poseidon Area permits in the Browse Basin and 29 percent of our working interest in the Goldwyer Shale in the Canning Basin permits. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

We operate five production sharing contracts (PSCs) in Indonesia: the offshore South Natuna Sea Block B and four onshore PSCs, the Corridor Block and South Jambi “B”, both located in South Sumatra, Warim in Papua, and we acquired Palangkaraya in Kalimantan in 2013. 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 3 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, and liquefied petroleum gas is sold locally for domestic consumption.

South Sumatra

The Corridor PSC consists of five oil fields and seven 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. Production from the South Jambi “B” PSC has reached depletion and field development has been suspended. We are evaluating options related to the future of this PSC.

Exploration

We own and operate an 80 percent interest in the Warim onshore exploration PSC in Papua. In 2013, we signed an amendment to the PSC, which enables us to continue exploration activities for the next five years and, if there are commercial discoveries, to continue development and production activities until 2032.

In January 2013, we signed a farm-in agreement to acquire a 49 percent interest in the Palangkaraya PSC. In November 2013, we completed the acquisition of Vela Energy Limited, which increased our interest in the Palangkaraya PSC to 100 percent. The Palangkaraya PSC consists of approximately 1.9 million net acres and is located in a frontier exploration area in central Kalimantan.

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.

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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.

Crude oil production at the Peng Lai 19-3 Field in Bohai Bay was curtailed in 2011, as a result of two separate seepage incidents which occurred near Platforms B and C. In February 2013, we received approval from China’s State Oceanic Administration (SOA) to resume normal production operations.

During 2012, we reached agreements with China’s Ministry of Agriculture and the SOA to resolve claims related to these seepage incidents. In the third quarter of 2013, we recognized an after-tax charge of $116 million for amounts previously paid by ConocoPhillips as operator. We do not anticipate further significant charges related to the 2011 seepage incidents.

Under the terms of the PSC, operatorship of the Peng Lai fields will transfer to our co-venturer on July 1, 2014, and we will maintain our interest as a non-operator.

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.

Exploration

In 2012, we entered into a joint study agreement with Sinopec Southern Exploration Company over the Qijiang shale gas block, located in the Sichuan Basin. The Qijiang Block covers approximately 1 million acres. 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.

In February 2013, we entered into a joint study agreement with PetroChina over the 500,000-acre Neijiang-Dazu shale block, also located in the Sichuan Basin. The study is for 19 months and encompasses a desktop study and drilling preparation.

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We own interests in five deepwater PSCs in Malaysia. Four are located off the eastern Malaysian state of Sabah: Block G, Block J, the Kebabangan Cluster (KBBC) and SB-311. In 2013, we executed our fifth PSC, deepwater Block 3E, located off the Malaysian state of Sarawak.

Block G

We have a 21 percent interest in the unitized Siakap North-Petai oil field, which is expected to begin producing in the first quarter of 2014, with estimated net annual peak production of 6 MBOED in 2015. Development of the Malikai oil field is underway with first production anticipated in the first half of 2017. Estimated net annual peak production of 19 MBOED is expected in 2018. We own a 35 percent interest in the Malikai, Pisagan, Ubah and Limbayong oil discoveries. The Limbayong-2 appraisal well, located approximately seven miles from Gumusut, was suspended as an oil discovery in the fourth quarter of 2013.

Block J

First production for Gumusut occurred from an early production system in the fourth quarter of 2012. Production from a permanent, semi-submersible floating production vessel is expected in the second quarter of 2014, with estimated net annual peak production of 30 MBOED anticipated in 2015.

KBBC

We own a 30 percent interest in the KBBC PSC. Development of the KBB gas field commenced in 2011, with first production anticipated in late 2014. Estimated net annual peak production of 28 MBOED is expected in 2015. The Kamunsu East-2 appraisal well, located approximately seven miles northwest of the KBB gas field, was suspended as a gas discovery in the third quarter of 2013.

Exploration

We own a 40 percent operating interest in SB-311, an exploration block encompassing 259,000 acres offshore Sabah. Seismic reprocessing and acquisition occurred in 2013, and initial exploration drilling is anticipated in 2015.

In November 2013, we acquired an 85 percent operating interest in deepwater Block 3E, which encompasses approximately 480,000 acres offshore Sarawak. The PSC carries a four-year exploration term during which we plan to drill two wells.

Bangladesh

Exploration

We hold 100 percent interests in two deepwater blocks in the Bay of Bengal, Blocks 10 and 11. In 2013, we performed 2-D seismic activities and are currently evaluating the results. Additionally, we were the high bidder on adjoining Shelf Block 7 in 2013 and are awaiting finalization of the PSC.

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Brunei

Exploration

We have a 6.25 percent working interest in deepwater Block CA-2, where exploration drilling has been ongoing since September 2011. Natural gas was discovered at the Kelidang NE well and the Keratau well in 2013. We are currently evaluating the results. Additionally, the Kempas #1 well was spud in late 2013 and declared a dry hole in January 2014.

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 consists of upstream natural gas production facilities, which produce approximately 1.4 billion gross cubic feet per day of natural gas from Qatar’s North Field over a 25 year life, in addition to a 7.8-million-gross-tonnes-per-year LNG facility. LNG is shipped in leased LNG carriers destined for sale globally.

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.

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OTHER INTERNATIONAL

The Other International segment includes exploration and producing operations in Libya and Russia, as well as exploration activities in Angola, Senegal and Azerbaijan. In 2013, we completed the sale of our Algeria business and the sale of our interest in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement (Kashagan), and we have agreements to sell our Nigeria business. Accordingly, results of these operations have been reclassified to discontinued operations for all periods presented. During 2013, operations in Other International contributed 4 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 interrupted in mid-2013, as a result of the shutdown of the Es Sider crude oil export terminal at the end of July 2013. Production remains shut-in, as the Es Sider Terminal shutdown has continued into the first quarter of 2014.

Exploration

We continued to participate in the ongoing exploration and appraisal programs within the Waha Concession in 2013. We completed drilling six appraisal wells and are currently drilling four appraisal wells. During 2014, we plan to drill six additional exploration and appraisal wells.

Polar Lights

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

Angola

Exploration

We have a 50 percent operating interest in Block 36 and a 30 percent operating interest in Block 37, both of which are located in Angola’s subsalt play trend. The two blocks total approximately 2.5 million acres. We have secured a rig for a four-well commitment program and plan to commence drilling in the second quarter of 2014.

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Senegal

Exploration

In 2013, we farmed into three exploration blocks in offshore Senegal with a 35 percent working interest. We have secured a rig for a two-well program and expect to begin drilling in the first half of 2014.

Kazakhstan

Exploration

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

Azerbaijan

Exploration

During 2013, we acquired an onshore 2-D seismic survey as part of a joint study with the State Oil Company of the Republic of Azerbaijan (SOCAR).

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.

*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 2013, the plant consumed 11 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.

In December 2012, we entered into agreements to sell our Nigeria business, which includes its upstream affiliates and Brass LNG. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Algeria

In November 2013, we sold our Algeria business. Production from discontinued operations for Algeria averaged 9 MBOED in 2013.

Kazakhstan

In October 2013, we sold our 8.4 percent interest in Kashagan.

For additional information on the Algeria and Kashagan dispositions, see Note 3—Discontinued Operations and Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

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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 primarily 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.

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 and Europe. These commodities are primarily sold under contracts with prices based on market indices, adjusted for location, quality and transportation.

Energy Partnerships

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. MWCC developed an interim containment system, which meets the U.S. Bureau of Safety and Environmental Enforcement requirements for a subsea well containment system that can respond to a deepwater well control incident in the U.S. Gulf of Mexico. To advance this capability, MWCC continues to develop an expanded containment system with significantly increased capacity. The expanded containment system should be available by the end of 2014.

Subsea Well Response Project

In 2011, we, along with several leading oil and gas companies, launched the Subsea Well Response Project (SWRP), a non-profit organization based in Stavanger, Norway, which was created to enhance the industry’s capability to respond to international subsea well control incidents. Through collaboration with Oil Spill Response Limited, a non-profit organization in the United Kingdom, subsea well intervention equipment is available for the industry to use in the event of a subsea well incident. This complements the work being undertaken in the United States by MWCC.

Technology

Our Technology organization has several technology programs, which focus on areas to support our business growth plans: developing unconventional reservoirs, producing oil sands and heavy oil economically with fewer emissions, advancing our competitiveness in deepwater development capabilities, improving the economic efficiency of our LNG and other gas solutions technologies, increasing recoveries from our legacy fields, and implementing sustainability measures.

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 12 more under construction and several feasibility studies ongoing.

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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, 2013. No difference exists between our estimated total proved reserves for year-end 2012 and year-end 2011, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2013.

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 200 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 any 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.

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 statistics published in the September 2, 2013, issue of the Oil and Gas Journal , we had the third-largest worldwide liquids and natural gas reserves for U.S.-based oil and gas companies in 2012. 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 safely operating oil and gas producing properties.

GENERAL

At the end of 2013, we held a total of 811 active patents in 55 countries worldwide, including 336 active U.S. patents. During 2013, we received 40 patents in the United States and 50 foreign patents. Our products and processes generated licensing revenues of $128 million in 2013. 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 $258 million, $221 million and $193 million in 2013, 2012 and 2011, respectively.

Health, Safety and Environment

Our Health, Safety and Environment (HSE) organization provides tools and support to our business units and staff groups to help them ensure world class health, safety and environmental performance. The framework through which we safely manage our operations, the HSE Management System Standard, emphasizes process safety, risk management, emergency preparedness and environmental performance, with an intense focus on occupational safety. In support of the goal of zero incidents, our HSE Excellence Process requires the business

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units to measure performance and drive continuous improvement. Assessments are conducted annually to capture progress and set new targets. We also have detailed processes in place to address sustainable development in our economic, environmental and social performance. Our processes, related tools and requirements focus on water, biodiversity and climate change, as well as social and stakeholder issues.

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 63 through 66 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2013 and those expected for 2014 and 2015.

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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