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.

In April 2012 the ConocoPhillips Board of Directors approved the separation of our downstream business into an independent, publicly traded energy company, Phillips 66. Each ConocoPhillips stockholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. The separation was completed on April 30, 2012, and activities related to Phillips 66 have been treated as discontinued operations for all periods prior to the separation.

In 2012 we agreed to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Nigeria and Algeria businesses (collectively, the “Disposition Group”). We sold our Nigeria business in the third quarter of 2014, and we sold Kashagan and our Algeria business in the fourth quarter of 2013. Results for the Disposition Group have been reported as discontinued operations in all periods presented. For additional information on all discontinued operations, see Note 2—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, 2014, ConocoPhillips employed approximately 19,100 people worldwide.

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SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 23—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, 2014, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

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 84 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 Libya, was 1,540 thousand barrels of oil equivalent per day (MBOED) in 2014, compared with 1,502 MBOED in 2013, an increase of 3 percent. Average liquids production increased 4 percent over the same period. The increase in total average production in 2014 primarily resulted from additional production from major developments, mainly from shale plays in the Lower 48 and the ramp up of production from Jasmine in the United Kingdom and Christina Lake in Canada, and increased drilling programs, mostly in the Lower 48, western Canada and Norway. These increases were largely offset by normal field decline, higher planned downtime, shut-in Libya production due to the closure of the Es Sider crude oil export terminal, and unfavorable market impacts. Excluding Libya, production from continuing operations was 1,532 MBOED in 2014, compared with 1,472 MBOED in 2013, an increase of 60 MBOED, or 4 percent.

Our total average realized price from continuing operations was $64.59 per BOE in 2014, a decrease of 4 percent compared with $67.62 per BOE in 2013, which reflected lower average realized prices for crude oil and natural gas liquids, partly offset by higher bitumen and natural gas prices. Our worldwide annual average crude oil sales price from continuing operations decreased 10 percent in 2014, from $103.32 per barrel in 2013 to $92.80 per barrel in 2014. Additionally, our worldwide average annual natural gas liquids prices from continuing operations decreased 6 percent, from $41.42 per barrel in 2013 to $38.99 per barrel in 2014. Our average annual worldwide natural gas sales price from continuing operations increased 8 percent, from $6.11 per thousand cubic feet in 2013 to $6.57 per thousand cubic feet in 2014. Average annual bitumen prices increased 3 percent, from $53.27 per barrel in 2013 to $55.13 per barrel in 2014.

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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 2014. Approximately 0.4 million of these acres are located in the National Petroleum Reserve—Alaska (NPRA) and 0.3 million are located in the Chukchi Sea. In 2014 Alaska operations contributed 20 percent of our worldwide liquids production and 1 percent of our natural gas production.

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 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. Development drilling at Kuparuk consists of rotary-drilled wells and horizontal multi-laterals from existing well bores utilizing coiled-tubing drilling.

The successful Shark Tooth delineation well extended the known Kuparuk accumulation to the southwestern area of the Kuparuk Field where construction of Drill Site 2S is progressing. The project was sanctioned in October 2014. First production is estimated in late 2015, with net peak production estimated at 5 MBOED in 2017.

In 2014 we received regulatory approvals to advance oil development targeting the West Sak reservoir in the Kuparuk River Unit. Pending a final investment decision, the development, 1H Northeast West Sak (NEWS), will include a nine-acre extension to an existing drill site allowing for new wells and associated facilities. We anticipate first production in 2017.

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 new drill site which will extend the Alpine reservoir west into the NPRA. Initial production is anticipated in late 2015, with net peak production estimated at 10 MBOED in 2016.

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The Greater Mooses Tooth Unit, the first unit established entirely within the NPRA, was formed in 2008. In 2014 we progressed development planning for the Greater Mooses Tooth #1 (GMT1) drill site. Delays in federal permitting and requirements, in addition to the current low commodity price environment, have resulted in deferral of the final investment decision. We plan to shoot seismic and continue engineering in 2015. GMT1 is planned to be connected by road to the CD5 drill site, and production will be transported by pipeline to the existing Alpine facilities for processing. 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. Our share of production from the units is primarily sold to local utilities and is also used to supply feedstock to the Kenai LNG Plant.

The Kenai LNG Facility includes a 1.6 million-tons-per-year capacity plant, as well as docking and loading facilities for LNG tankers. LNG from the plant has historically been transported and sold to utility companies in Japan. The plant was idled in late-2012; however, due to a change in market conditions, including additional gas supplies, we were granted a two-year export license from the U.S. Department of Energy (DOE) in April 2014 to export up to 40 billion cubic feet of LNG from the facility. As a result, we shipped 5 cargoes of LNG from the Kenai Facility to Asia in 2014.

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).

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 liquefy and export 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.

The proposed AKLNG natural gas liquefaction plant and terminal would be located in the Nikiski area on the Kenai Peninsula, approximately 60 miles southwest of Anchorage, along the Cook Inlet. In January 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. During 2014 general legislation was enacted by the State of Alaska, and a joint venture agreement for the preliminary front-end engineering and design phase of the project was executed. The AKLNG Project will require many major federal permits, and in July 2014 an application for an LNG export license was filed with the U.S. DOE to export up to 20 million metric tons a year of LNG for 30 years. In November 2014 the U.S. DOE authorized the export of LNG to free trade agreement (FTA) countries, and authorization to export to non-FTA countries remains pending. In September 2014 the Federal Energy Regulatory Commission (FERC) accepted the project into pre-file status, which initiates the lengthy environmental and safety reviews required to design, permit, construct and operate the plants and pipeline.

Significant engineering, technical, regulatory, fiscal, commercial and permitting issues would need to be resolved prior to a final investment decision on the potential $45 billion to $65 billion (gross) project.

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Exploration

In 2014 we drilled two exploration wells within the Greater Mooses Tooth Unit: the Rendezvous 3 and Flattop-1. Potential development of the Rendezvous 3 area is under evaluation. Flattop-1 encountered hydrocarbons but was expensed. The well is temporarily abandoned and available for testing in the future. In 2013 we drilled in the Cassin Prospect, located in the Bear Tooth Unit in the northeast NPRA, and we are continuing to evaluate development options. The Moraine Prospect, located on the western flank of the Kuparuk Field, was tested in 2013 and began producing in 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 charters third-party vessels as necessary. The tankers primarily deliver oil from Valdez, Alaska, to refineries on the west coast of the United States.

LOWER 48

The Lower 48 segment consists of operations located in the U.S. Lower 48 states and exploration activities in the Gulf of Mexico. The Lower 48 business is organized within four regions covering the Gulf Coast, Mid-Continent, Rockies and San Juan. As a result of increasing shale opportunities, we have directed our investments toward certain higher-margin, liquids-rich plays. We hold 15 million net onshore and offshore acres in the Lower 48. In 2014 the Lower 48 contributed 32 percent of our worldwide liquids production and 38 percent of our natural gas production.

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Onshore

We hold 13 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:

The majority of our 2014 onshore production originated from the Eagle Ford, San Juan, Permian and Bakken. Onshore activities in 2014 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 2014 included the following:

Gulf of Mexico

At year-end 2014, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one operated field and three fields operated by co-venturers, including:

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Exploration

At December 31, 2014, we held approximately 2.1 million net acres in the deepwater Gulf of Mexico.

We own a 30 percent nonoperated working interest in the Shenandoah discovery. The results of the first Shenandoah appraisal well were announced in 2013 and confirmed Shenandoah as a significant oil discovery. The second Shenandoah down dip appraisal well was spud in 2014 and expensed as a dry hole. Planning is underway for the next appraisal well, which is expected to spud in the second quarter of 2015.

As of December 2014, we owned a 35 percent nonoperated interest in the Gila Prospect and a 100 percent interest in one Gibson Prospect block, both located in the Keathley Canyon area of the Gulf of Mexico. In January 2015 we entered into an exchange agreement with Chevron Corporation and BP p.l.c. to align working interests in order to progress a hub development. As a result, our interests in both the Gila and the Gibson prospects were adjusted to 30 percent. The Gila exploration well was announced as a discovery in 2013 and is currently being appraised.

Other ongoing drilling activities at the end of 2014 included a Tiber appraisal well, in which we own an 18 percent working interest.

The nonoperated Coronado wildcat and appraisal wells and the Deep Nansen wildcat well were declared dry holes in 2014.

In support of our Gulf of Mexico exploration program, we secured access to two new-build deepwater drillships. The first drillship commenced drilling on our operated Harrier Prospect in February 2015, and we anticipate delivery of the second drillship during 2015. Both will provide rig availability for our operated drilling program. We expect to drill two wells in 2015 utilizing the first drillship.

In 2014 we actively pursued the exploration and appraisal of our existing unconventional resource plays, including the Niobrara play in the Denver-Julesburg Basin, and the Wolfcamp and Bone Springs plays in the Delaware Basin. During 2014 we acquired approximately 13,000 net additional acres in various resource plays across the Lower 48, which included the Permian, Niobrara and Eagle Ford plays, maintaining our significant acreage position in Lower 48 shale plays of approximately 2.7 million net acres. During 2014 we drilled a total of 36 unconventional exploration wells in the Niobrara play and the Delaware Basin.

In 2015 we plan to continue to explore and appraise certain unconventional plays and assess new unconventional opportunities, but at a slower pace in anticipation of weak 2015 commodity prices.

Facilities

Freeport LNG Terminal

In July 2013 we agreed with Freeport LNG Development, L.P. to terminate our long-term agreement 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. The termination agreement was 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. These conditions were satisfied in the fourth quarter of 2014, and we paid Freeport LNG a termination fee of $522 million. Freeport LNG repaid the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, resulted in a one-time net cash outflow of $63 million for us. In addition, we recognized an after-tax charge to earnings of $540 million in the fourth quarter of 2014, and our terminal regasification capacity has been 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

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will be reduced to zero. As a result of this transaction, we anticipate saving approximately $50 to $60 million per year in costs over the next 18 years. For additional information, see Note 3—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, with a combined net book value of approximately $290 million at December 31, 2014. 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. Utilization of the terminal has been and is expected to be limited, as market conditions currently favor the flow of LNG to European and Asian markets. As a result, we are evaluating opportunities to optimize the value of the terminal facilities.

Great Northern Iron Ore Properties Trust

ConocoPhillips holds the reversionary interest in the Great Northern Iron Ore Properties trust (the Trust), a grantor trust that owns mineral interests in the Mesabi Iron Range in northeastern Minnesota and certain other personal property. Pursuant to the terms of the Trust Agreement, the Trust terminates on April 6, 2015. At the end of the wind-down period, documents memorializing ConocoPhillips’ ownership of certain Trust property, including all of the Trust’s mineral properties and active leases, will be delivered to ConocoPhillips. The Trustees currently anticipate the wind-down process, final distribution and dissolution of the Trust will be completed by the end of 2016. At that time, we expect to recognize the fair value of the Trust’s net assets transferred to us.

Other

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Western Canada

Our operations in western Canada extend across Alberta, British Columbia and Saskatchewan. We operate or have ownership interests in approximately 80 natural gas processing plants in the region, and, as of December 31, 2014, held leasehold rights in 5.7 million net acres in western Canada. Our investments in 2014 were focused mainly on higher-margin, liquids-rich opportunities in the following three core development areas:

Assets located outside the three core development areas are focused on production optimization and consist of 2.6 million net acres of leasehold rights. These assets averaged 29 MBOED of net production in 2014.

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.

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Foster Creek is located approximately 200 miles northeast of Edmonton, Alberta. There are six producing phases at Foster Creek, Phases A through F, with one more under construction, Phase G. First production for Phase F was achieved in the third quarter of 2014, and first production for Phase G is anticipated in 2016. Due to the substantial decline in crude oil prices, construction on Phase H has been deferred in order to preserve cash. Phases G and H are each expected to add 30 MBOED of gross production capacity, with an additional 50 MBOED from potential optimization. In the fourth quarter of 2014, regulatory approval was received for Phase J, which should add approximately 50 MBOED of gross production capacity. With the additional phases and potential optimization, Foster Creek has the potential to reach approximately 310 MBOED of total gross production capacity.

Christina Lake is located approximately 75 miles south of Fort McMurray, Alberta. There are five producing phases at Christina Lake, Phases A through E, with plans underway for Phase F. Gross production at Christina Lake increased approximately 40 percent in 2014, mostly as a result of Phase E reaching full capacity in the second quarter of 2014, in addition to strong facility uptime and strong well performance. During 2014 construction continued on Phases F and G. Phase F is expected to commence production in the second half of 2016 and add another 50 MBOED of gross production capacity. Further construction on Phase G has been deferred to preserve cash. An application for Phase H was submitted for regulatory review in 2013. With the additional expansion phases and optimization work, total gross production capacity from Christina Lake has the potential to reach approximately 310 MBOED.

Narrows Lake is located near Christina Lake. Plant construction on Phase A continued in 2014; however, further work at Narrows Lake has been deferred to preserve cash. Narrows Lake is estimated to reach 130 MBOED of total gross production capacity.

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. In 2014 we decided not to pursue future development of the Amauligak discovery. Accordingly, we recorded a $109 million after-tax impairment of undeveloped leasehold costs associated with the offshore Amauligak discovery, Arctic Islands and other Beaufort properties. We, however, remain committed to the potential of the area, should technology and commodity prices improve.

Exploration

We hold exploration acreage in four areas of Canada: onshore western Canada, offshore eastern Canada, the Mackenzie Delta/Beaufort Sea Region and the Arctic Islands. Our primary exploration focus is on liquids-rich unconventional plays in western Canada and conventional exploration offshore eastern Canada.

During 2014 we entered into a farm-in agreement to acquire a 30 percent nonoperated interest in six exploration licenses covering approximately five million gross acres in the deepwater Shelburne Basin, offshore Nova Scotia. Pending regulatory approval, we anticipate drilling will begin in the second half of 2015. In December 2014 we participated in a successful bid for one exploration license covering 0.7 million gross acres located in the Flemish Pass Basin, offshore Newfoundland. In January 2015 we were awarded the license, in which we hold a 30 percent nonoperated interest.

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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 2014 we continued to drill 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.

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 the Barents Sea, offshore Norway; Central North Sea and west of Shetland, offshore United Kingdom; and Baffin Bay and Greenland Sea, offshore Greenland. In 2014 operations in Europe contributed 15 percent of our worldwide liquids production and 12 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. Ekofisk South achieved first production in 2013 and continued to ramp up during 2014, while Eldfisk II achieved startup in January 2015. Ekofisk South, along with Eldfisk II and other developments offshore Norway, will contribute additional production over the coming years, as additional wells come online.

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, as well as the Aasta Hansteen development. The operator is targeting first gas for Aasta Hansteen by late 2017.

Exploration

During 2014 we participated in two nonoperated wildcat wells in the Barents Sea; both were declared dry holes. In the Visund area of the North Sea, we participated in the Helene/Methone nonoperated exploration well, which was a gas discovery and is currently being evaluated for development. We also participated in the

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Barents Sea 3-D seismic group study over the recently opened southeast Barents area. In 2014 we were awarded two new North Sea licenses from the 2013 Awards in Pre-defined Areas licensing round: PL044B and PL736S, in which we will own a 41.88 percent operating interest and a 20 percent nonoperated interest, respectively.

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.

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. The Britannia Long-Term Compression Project, which consisted of a new mono-column design compression facility for the Britannia Platform, achieved startup in the third quarter of 2014 and has increased Britannia’s natural gas production by approximately 90 MMCFD gross.

The J-Area consists of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. The Jasmine Field is a high-pressure, high-temperature gas condensate reservoir located approximately six miles west of the Judy Platform. The 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. First production from Jasmine commenced in late-2013 and continued to ramp up during 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 2017.

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Exploration

During 2014 the drilling and testing of three successful near-field prospects in the Greater Clair area was completed, and a fourth prospect is currently being tested. In the J-Area, well operations on the Jade South discovery, previously called the Romeo Prospect, were completed, and production was tied-in to the Jade Field during the second quarter of 2014. Additionally, a Jasmine exploration well was drilled and expensed as a dry hole in 2014, and a second well was spud in early 2015. We were also awarded three new licenses in the U.K. Continental Shelf 28 ^th Licensing Round, all of which are in proximity to existing acreage.

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.

Greenland

Exploration

In 2014 we conducted field-based, metocean studies in Baffin Bay in Block 2011/11 of our operated Qamut license. Additionally, we participated in a 2-D seismic acquisition program in Northeast Greenland, as part of our work program obligation in our nonoperated Avinngaq license.

ASIA PACIFIC AND MIDDLE EAST

The Asia Pacific and Middle East segment has exploration and production operations in China, Indonesia, Malaysia, Australia and Timor Leste; producing operations in Qatar; and exploration activities in Bangladesh, Brunei and Myanmar. In 2014 operations in the Asia Pacific and Middle East segment contributed 13 percent of our worldwide liquids production and 31 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 from Train 1. Following commissioning, the LNG will be sold to Sinopec under a 20-year sales agreement for up to 4.3 million metric tonnes of LNG per year. Startup of the second LNG train is expected to

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occur six-to-nine months following the startup of Train 1. 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 Japan-based Kansai Electric Power Co., Inc. has agreed to purchase approximately 1 million metric tonnes of LNG per year for 20 years.

APLNG has an $8.5 billion project finance facility, of which $8.1 billion had been drawn from the facility at December 31, 2014. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility until the project achieves financial completion. For additional information, see Note 3—Variable Interest Entities (VIEs), Note 6—Investments, Loans and Long-Term Receivables, and Note 11—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 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 2014 we sold 154 billion gross cubic feet of LNG to utility customers in Japan.

The Bayu-Undan Phase Three Development consists of two standalone, subsea horizontal wells tied back to the existing drilling, production and processing platform. In 2014 we completed the fabrication and installation of platform risers, topsides piping, wellheads and trees. Development drilling commenced in the second half of 2014, with initial production estimated in the first quarter of 2015. The development is expected to average an additional 100 MMCFD gross over two years.

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 hearing was conducted in June 2014, and we are currently awaiting the Tribunal’s decision. For additional information, see Note 12—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. Following agreement between the governments in September 2014, this arbitration is currently suspended until March 2015. The CMATS arbitration does not directly impact our underlying interests in Sunrise; however, we and the Sunrise co-venturers are unable to commit to further commercial and technical work activities due to the uncertainty created by the lack of government alignment. Accordingly, current activities are restricted to compliance and social investment, as well as maintaining relationships and development options for Sunrise.

Exploration

We operate two exploration permits in the Browse Basin, offshore northwest Australia, in which we own a 40 percent interest in permits WA-315-P and WA-398-P, of the Greater Poseidon Area. Phase I of the Browse Basin drilling campaign in 2009/2010 resulted in three discoveries in the Greater Poseidon Area: Poseidon-1, Poseidon-2 and Kronos-1. Phase II of the drilling campaign resulted in

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five additional discoveries: Boreas-1, Zephyros-1, Proteus-1 SD2, Poseidon-North-1 and Pharos-1. All wells have been completed, plugged and abandoned. The Grace-1 well, drilled in permit WA-314-P, was declared a dry hole in early 2014, and the permit was subsequently relinquished in June 2014.

We operate two retention leases in the Bonaparte Basin, offshore northern Australia, where we own a 37.5 percent interest in leases NT/RL5 and NT/RL6. A three-well drilling campaign commenced in 2014 to further evaluate the field’s potential. The first two wells, Barossa-2 and Barossa-3, encountered hydrocarbons. The third well, Barossa-4, was spud in January 2015.

We own a 46 percent working interest in four exploration permits within the Canning Basin of Western Australia, which covers approximately 10 million gross acres. In October 2014 we exercised our right of withdrawal from the four permits, which is pending regulatory approval. The leases will expire in 2015.

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 Palangkaraya in central Kalimantan. 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 a 100 percent interest in the Palangkaraya PSC in central Kalimantan. Exploration drilling is scheduled to begin in the first quarter of 2015.

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.

Effective July 1, 2014, operatorship of the Peng Lai fields transferred to China National Offshore Oil Corporation (CNOOC), in accordance with terms of the PSC. We retain a 49 percent nonoperated interest.

The Panyu development, located in Block 15/34 in the South China Sea, is comprised of three oil fields: Panyu 4-2, Panyu 5-1 and Panyu 11-6. The PSC for the block is scheduled to expire in September 2018, at which time we will relinquish all of our working interest in the block.

Exploration

In 2014 we participated in four successful appraisal wells in the Peng Lai fields, which will be used to optimize our growth program.

In 2012 we entered into a joint study agreement (JSA) with Sinopec Southern Exploration Company over the Qijiang shale gas block, located in the Sichuan Basin. The Qijiang Block covers approximately one million acres. In February 2014 we were informed the majority of this area had been declared a military exclusion zone and would not be open for foreign cooperation. As a result, we are in the process of terminating the JSA.

In February 2013 we entered into a JSA with PetroChina over the 500,000-acre Neijiang-Dazu shale block, also located in the Sichuan Basin. In 2014 we decided not to pursue a PSC over the area.

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. Our fifth PSC, deepwater Block 3E, is located off the Malaysian state of Sarawak.

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Block G

We have a 21 percent interest in the unitized Siakap North-Petai oil field, which began producing in the first quarter of 2014. Estimated net annual peak production of 6 MBOED is anticipated in 2015. Development of the Malikai oil field is underway with first production anticipated in 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 drilled in 2013 and resulted in an oil discovery. Development options are being evaluated.

Block J

First production for Gumusut occurred from an early production system in 2012. Production from a permanent, semi-submersible floating production vessel was achieved in October 2014, with estimated net annual peak production of 26 MBOED anticipated in 2016. Unitization of the Gumusut Field with Brunei was recorded in 2014 and reduced our ownership interest from 33 percent to 29 percent.

KBBC

We own a 30 percent interest in the KBBC PSC. Development of the KBB gas field commenced in 2011, and first production was achieved in November 2014; however, gas sales have not yet commenced due to ongoing repairs on a third-party pipeline. We anticipate the repairs will be completed in the second half of 2015. Estimated net annual peak production of 28 MBOED is expected in 2016. Kamunsu East is being evaluated for development options.

Exploration

We own a 40 percent operating interest in SB-311, an exploration block encompassing 259,000 gross acres offshore Sabah. We plan to commence drilling in 2015 under a two-well commitment program.

We own an 85 percent operating interest in deepwater Block 3E, which encompasses approximately 480,000 gross acres offshore Sarawak. Seismic acquisition and reprocessing occurred in 2014, and drilling is planned for 2016-2017.

Bangladesh

Exploration

In 2014 we relinquished the PSC for two deepwater blocks in the Bay of Bengal, Blocks 10 and 11. We were the high bidder on adjoining Deepwater Blocks 12, 16 and 21 in 2014 and are awaiting finalization of the PSC.

Brunei

Exploration

We have a 6.25 percent working interest in the deepwater Block CA-2 PSC, which has an exploration period through December 2018. Exploration has been ongoing since September 2011. The Kempas-1 well was declared a dry hole in January 2014.

Myanmar

Exploration

In 2014 we were awarded deepwater Block AD-10 in the 2013 Myanmar offshore oil and gas bidding round. Finalization of the PSC is anticipated to occur in early 2015.

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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 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.

OTHER INTERNATIONAL

The Other International segment includes exploration and producing operations in Libya and Russia, as well as exploration activities in Colombia, Poland, Angola, Senegal and Azerbaijan. During 2014 operations in Other International contributed 1 percent of our worldwide liquids production.

In 2014 we completed the sale of our Nigeria business. Results of operations for Nigeria have been reported as discontinued operations for all periods presented. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

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. The Es Sider Terminal briefly reopened in the third quarter of 2014 and production and liftings resumed temporarily; however, further disruptions occurred in December 2014, and production is shut in again. The 2015 drilling program remains uncertain as a result of the ongoing civil unrest.

Exploration

During 2014 we completed drilling four appraisal wells. No decision has been made regarding the 2015 drilling program.

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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 gross acres. We have secured a rig for a four-well commitment program and commenced drilling in the second quarter of 2014. In November 2014 we plugged and abandoned the Kamoxi-1 exploration well as a dry hole. Kamoxi-1 is located in Block 36 offshore Angola. We subsequently spud the Omosi-1 well in adjacent Block 37, which is the second wildcat in our planned four-well exploration program in the Kwanza Basin.

Senegal

Exploration

We have a 35 percent working interest in three exploration blocks offshore Senegal. In October 2014 we discovered a working petroleum system at the FAN-1 exploration well. In addition, in November 2014 we confirmed oil was discovered in the SNE-1 well, the second of the two-well program. Further evaluation of both wells is required to determine commerciality. We have the option to become operator of the project if it advances to development.

Azerbaijan

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.

Poland

Exploration

We are participating in a shale gas venture in Poland and own a 100 percent interest in Lane Energy Poland. We operate three western Baltic Basin concessions, which encompass approximately 500,000 gross acres. A horizontal well was drilled and completed in 2014, and further evaluation continues.

Colombia

Unconventional Exploration

We have a 70 percent nonoperated working interest for deep rights in the Santa Isabel Block in the Middle Magdalena Basin, which covers approximately 71,000 net acres. During 2014 work continued on the environmental impact assessment for an area of the Santa Isabel block in preparation for future drilling.

We also hold 30 percent nonoperated working interests in three blocks in the Middle Magdalena Basin, which cover approximately 116,000 net acres. Exploration drilling commenced in October 2014 at the Picoplata-1 well, located on the VMM3 Block, with completion targeted during the first quarter of 2015.

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Venezuela

In October 2014 we filed for arbitration under the rules of the International Chamber of Commerce (ICC) against Petroleos de Venezuela (PDVSA), the Venezuela state oil company, for contractual compensation related to the Petrozuata and Hamaca heavy crude oil projects. The ICC arbitration is a separate and independent legal action from the investment treaty arbitration against the government of Venezuela, which is currently proceeding before an arbitral tribunal under the World Bank’s International Centre for Settlement for Investment Disputes (ICSID). ICSID is determining the damages owed to ConocoPhillips as a result of Venezuela’s unlawful expropriation of ConocoPhillips’ significant oil investments in the Petrozuata and Hamaca heavy crude oil projects and the offshore Corocoro development project in June 2007. For additional information, see Note 12—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 currently proceeding to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims. For additional information, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Discontinued Operations

Nigeria

In July 2014 we sold our Nigeria business. Production from discontinued operations for Nigeria averaged 21 MBOED in 2014.

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. In January 2015 MWCC announced acceptance of its expanded containment system (ECS). The ECS complements the capabilities and capacities put into place with its interim containment system, which the

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industry has been relying on since 2011. Equipment from both systems have been combined to form MWCC’s containment system, which meet 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.

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 feasibility studies ongoing.

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, 2014. No difference exists between our estimated total proved reserves for year-end 2013 and year-end 2012, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2014.

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 3 trillion cubic feet of natural gas, including approximately 500 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.

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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 1, 2014, issue of the Oil and Gas Journal , we were the third-largest U.S.-based oil and gas company in worldwide liquids and natural gas production and reserves in 2013. 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 2014, we held a total of 912 active patents in 56 countries worldwide, including 367 active U.S. patents. During 2014 we received 51 patents in the United States and 74 foreign patents. Our products and processes generated licensing revenues of $46 million in 2014. 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 $263 million, $258 million and $221 million in 2014, 2013 and 2012, 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 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 59 through 62 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2014 and those expected for 2015 and 2016.

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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