CONOCOPHILLIPS - Annual Report: 2015 (Form 10-K)

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2015

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended         December 31, 2015                                             

OR

For the transition period from                                  to                                 

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

600 North Dairy Ashford

Houston, TX 77079

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: 281-293-1000

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

[x]  Yes    [  ]  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

[  ]  Yes    [x]  No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

[x]  Yes    [  ]  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

[x]  Yes    [  ]  No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [x]    Accelerated filer [  ]    Non-accelerated filer [  ]    Smaller reporting company [  ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). [  ]  Yes    [x]  No

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $61.41, was $75.7 billion.

The registrant had 1,236,202,726 shares of common stock outstanding at January 31, 2016.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 10, 2016 (Part III)

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TABLE OF CONTENTS

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PART I

Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and 2—Business and Properties, contain forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 72.

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 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Headquartered in Houston, Texas, we have operations and activities in 21 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 tight oil and oil sands assets; lower-risk legacy assets in North America, Europe, Asia and Australia; several major international developments; and an inventory of global conventional and unconventional exploration prospects.

At December 31, 2015, ConocoPhillips employed approximately 15,900 people worldwide.

We are marketing certain non-core assets across all of our segments. For additional information on asset sales, see the “Outlook” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

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SEGMENT AND GEOGRAPHIC INFORMATION

Effective November 1, 2015, the Other International and historically presented Europe segments were restructured to align with changes to our internal organization structure. The Libya business was moved from the Other International segment to the historically presented Europe segment, which is now renamed Europe and North Africa. Accordingly, results of operations for the Other International and Europe and North Africa segments have been revised in all periods presented. There was no impact on our consolidated financial statements, and the impact on our segment presentation is immaterial. For operating segment and geographic information, see Note 24—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, 2015, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, and Qatar.

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 (MCF) 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 was 1,589 thousand barrels of oil equivalent per day (MBOED) in 2015, compared with 1,540 MBOED, including Libya, in 2014, an increase of 3 percent. The increase in total average production in 2015 primarily resulted from additional production from major developments, including tight oil plays in the Lower 48; Gumusut in Malaysia; APLNG in Australia; Greater Britannia projects and the J-Area in the U.K.; and the ramp-up of Foster Creek Phase F in Canada. Improved well performance, mostly in the Lower 48, western Canada and Norway, and lower turnaround activity also contributed to higher production in 2015. These increases were largely offset by normal field decline. Production from continuing operations was 1,589 MBOED in 2015, compared with 1,532 MBOED in 2014, excluding Libya, an increase of 57 MBOED, or 4 percent. Full-year production from assets sold or under agreement in 2015 was 64 MBOED.

Our total average realized price from continuing operations was $34.34 per BOE in 2015, a decrease of 47 percent compared with $64.59 per BOE in 2014, which reflected lower average realized prices across all commodities. Our worldwide annual average crude oil price from continuing operations decreased 48 percent in 2015, from $92.80 per barrel in 2014 to $48.26 per barrel in 2015. Additionally, our worldwide annual average natural gas liquids prices from continuing operations decreased 54 percent, from $38.99 per barrel in 2014 to $17.79 per barrel in 2015. Our worldwide annual average natural gas price from continuing operations decreased 40 percent, from $6.57 per MCF in 2014 to $3.96 per MCF in 2015. Average annual bitumen prices also decreased 66 percent, from $55.13 per barrel in 2014 to $18.72 per barrel in 2015.

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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 0.7 million net undeveloped acres at year-end 2015. Approximately 0.4 million of these acres are located in the National Petroleum Reserve—Alaska (NPRA) and the North Slope, and 0.3 million are located in the Chukchi Sea. In 2015, Alaska operations contributed 19 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 plant which processes natural gas to recover natural gas liquids before 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.

Drill Site 2S, in the southwestern area of the Kuparuk Field, was sanctioned in October 2014. First oil was achieved in October 2015 with net peak production estimated at 5 MBOED in 2016.

The 1H Northeast West Sak (NEWS) oil development targeting the West Sak reservoir in the Kuparuk River Unit, was sanctioned in March 2015. First production is anticipated 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. In October 2015, first oil was achieved at Alpine West CD5, a new drill site which extends the Alpine reservoir west into the NPRA. Net peak production is estimated at 10 MBOED in 2016.

The Greater Mooses Tooth Unit, the first unit established entirely within the NPRA, was formed in 2008. In 2015, we received permit approvals and sanctioning from the regulatory agencies for the Greater Mooses Tooth #1 (GMT1) drill site. GMT1 is planned to be connected by road to the CD5 drill site, and production

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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 six cargoes of LNG from the Kenai Facility to Asia in 2015. In February 2016, our export license was renewed for an additional two years.

In the first quarter of 2016, we entered into an agreement to sell our interest in the Beluga River Unit natural gas field in the Cook Inlet Area. The transaction is expected to close in the second quarter of 2016.

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 second quarter 2016, which is estimated to send 400 net barrels of oil equivalent per day (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 (AGDC), 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 several 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 and June 2015, the U.S. DOE authorized the export of LNG to free trade agreement (FTA) and non-FTA countries, respectively. 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. In March 2015, the FERC issued their Notice of Intent (NOI) to prepare the Environmental Impact Statement for AKLNG and begin the National Environmental Policy Act period to seek public comment. In October 2015, the Alaska Oil and Gas Conservation Commission (AOGCC) issued orders for gas offtake at Prudhoe Bay and Point Thomson. In December 2015, AGDC acquired the interest in the AKLNG Project previously held by TransCanada Corporation. On December 31, 2015 the HOA expired by its own terms. Commercial negotiations and planning for front-end engineering and design are ongoing.

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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.

Exploration

We plan to drill two to three exploration wells in 2016 in the NPRA.

Our plans to drill an exploration well in the Chukchi Sea have been cancelled due to the current market environment, regulatory uncertainty and expiry of the primary lease term in 2020. As a result, we recorded a $406 million after-tax charge for leasehold and capitalized interest impairment and dry hole expense in the fourth quarter of 2015.

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 three regions covering the Gulf Coast, Mid-Continent and Rockies. As a result of tight oil opportunities, we have directed our investments toward certain shorter cycle time, low cost-of-supply plays. In July 2015, we announced our plan to reduce future deepwater exploration spending and terminated our Gulf of Mexico deepwater drillship contract with Ensco. We hold 14.3 million net onshore and offshore acres in the Lower 48. In 2015, the Lower 48 contributed 33 percent of our worldwide liquids production and 36 percent of our natural gas production.

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Onshore

We hold 12.4 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 2.6 million net acres in the following areas:

The majority of our 2015 onshore production originated from the Eagle Ford, San Juan, Permian and Bakken. Onshore activities in 2015 were centered mostly on continued development of emerging and existing assets, with an emphasis on areas with low cost of supply, particularly in growing unconventional plays. The 2015 drilling activity levels declined relative to 2014 due to reduced capital spending in the low commodity price environment. Our major focus areas in 2015 included the following:

In the fourth quarter of 2015, we completed the sale of certain non-core assets in East Texas and North Louisiana and South Texas. Production from the assets sold was 33 MBOED, approximately 6 percent of the total Lower 48 segment production in 2015.

Gulf of Mexico

At year-end 2015, 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

In the third quarter of 2015, we decided not to conduct further activity on certain Gulf of Mexico leases. At December 31, 2015, we held approximately 1.8 million net acres in the deepwater Gulf of Mexico.

During 2015, we conducted appraisal drilling at Shenandoah, Tiber, and Gila. The nonoperated Gibson exploration and Tiber appraisal wells, and the ConocoPhillips operated Melmar exploration well are currently drilling.

We own a 30 percent nonoperated working interest in the Shenandoah discovery, which was announced in 2009. The third Shenandoah down dip appraisal well was spud in 2015, and planning is underway for the next appraisal well, which is expected to spud in the first half of 2016.

The operated Harrier and nonoperated Vernaccia wells were expensed as dry holes in 2015. The operator of the Gila prospect has elected to discontinue exploration and appraisal activity. Accordingly, we recorded $111 million in after-tax dry hole expense for a previously suspended well in the Gila prospect, and a $100 million charge for the impairment of undeveloped leasehold costs.

Our onshore focus areas include the Niobrara in the Denver-Julesburg Basin and the Wolfcamp and Bone Springs in the Delaware Basin, as well as several emerging plays. In 2015, we drilled 21 unconventional wells in the Delaware Basin. We continue to assess and appraise this and other unconventional opportunities.

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 conditions were satisfied in 2014. 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 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 17 years. For additional information, see Note 7—Investments, Loans and Long-Term Receivables, 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 $273 million at December 31, 2015. 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 Qatar Liquefied Gas Company Limited (3) (QG3) 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

We hold the interest in the Great Northern Iron Ore Properties trust (the Trust), a grantor trust that owns mineral and surface interests in the Mesabi Iron Range in northeastern Minnesota and certain other personal property. Pursuant to the terms of the Trust Agreement, the Trust terminated on April 6, 2015. At the end of the wind-down period, documents memorializing our ownership of certain Trust property, including all of the

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Trust’s mineral properties and active leases, will be delivered to us. 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

CANADA

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. In 2015, operations in Canada contributed 21 percent of our worldwide liquids production and 18 percent of our natural gas production.

Western Canada

Our operations in western Canada extend across Alberta and British Columbia. We operate or have ownership interests in approximately 50 natural gas processing plants in the region, and, as of December 31, 2015, held leasehold rights in 3.2 million net acres in western Canada. Our investments in 2015 were focused mainly on opportunities in the following three core development areas:

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Assets located outside these development areas are focused on production optimization. In the fourth quarter of 2015, we finalized sales of certain non-core assets in British Columbia, Saskatchewan and Alberta. Production from the assets sold was 27 MBOED, approximately 9 percent of the total Canada segment production in 2015. At December 31, 2015, the company held 0.1 million net acres of leasehold rights in these areas.

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.

Foster Creek is located approximately 200 miles northeast of Edmonton, Alberta. There are six producing phases at Foster Creek, Phases A through F, with construction continuing on Phase G. Net production at Foster Creek increased approximately 12 MBOED, mainly as a result of a continued ramp up toward full capacity. In the fourth quarter of 2014, FCCL received regulatory approval for Phase J.

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 construction continuing on Phase F. In late 2015, an optimization project was completed at Christina Lake that increased gross production capacity to 160 MBOED, with incremental production expected to ramp up during 2016. In the fourth quarter of 2015, regulatory approval was received for Phase H development.

Narrows Lake Phase A, was sanctioned in late 2012 and is expected to have 45 MBOED of production capacity; however, construction has been deferred.

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 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. In the fourth quarter of 2015, we spudded the first of two exploration well commitments in offshore Nova Scotia. The second exploration well is anticipated to begin drilling in the second quarter of 2016. In December 2014, we participated in a successful bid for one

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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. Seismic surveys of the subsurface were completed in 2015.

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 2015, we completed a lease swap and continued to drill exploration and appraisal wells in the Montney play, which extends from British Columbia into Alberta.

In the fourth quarter of 2015, we recorded dry hole expense of $185 million after-tax associated with our Horn River, Northwest Territories, Thornbury and Saleski properties, and an impairment charge of $75 million after-tax for unproved properties in the Duvernay, Thornbury, Saleski and Crow Lake areas.

EUROPE AND NORTH AFRICA

The Europe and North Africa segment consists of operations and exploration activities in Norway, the United Kingdom and Libya. In 2015, operations in Europe and North Africa contributed 14 percent of our worldwide liquids production and 12 percent of natural gas production.

Norway

The Greater Ekofisk Area is located approximately 200 miles offshore Stavanger, Norway in the North Sea, and comprises three producing fields: Ekofisk, Eldfisk and Embla. Crude oil is exported to Teesside, England, and the natural gas is exported to Emden, Germany. Ekofisk South achieved first production in 2013, while Eldfisk II achieved startup in January 2015. Continued development drilling in the Greater Ekofisk Area 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 Scottish Area Gas Evacuation (SAGE) terminal at St. Fergus, Scotland, through the SAGE pipeline.

The Heidrun Field is located in the Norwegian Sea. Produced crude oil is stored in a floating storage unit and exported via 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 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 2018.

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Exploration

ConocoPhillips participated in four nonoperated exploration and appraisal wells in the Oseberg, Visund and Aasta Hansteen areas. Two wells in the Oseberg area were discoveries and were put on production; the others were discoveries currently undergoing evaluation. ConocoPhillips was awarded two new exploration licenses in early 2015, PL044C and PL782S with interests of 41.9 and 40.0 percent, respectively. Two more licenses were awarded in early 2016, PL845 and PL782SB, both with interests of 40.0 percent.

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 November 2015, we sold our 1.9 percent interest in Norwegian Continental Shelf Gas Transportation (Gassled), which owns most of the Norwegian gas transportation infrastructure.

United Kingdom

Britannia is one of the largest natural gas and condensate fields in the North Sea. We assumed operatorship of Britannia in August 2015, following the acquisition of third party equity in Britannia Operator Limited, which is now wholly owned by ConocoPhillips. 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. Project startups for the Brodgar H3 susbsea tieback, and Enochdhu, a single well tie back to Callanish, were achieved in the first and second quarters of 2015, respectively. These projects increased Britannia’s production in 2015 by 13.8 MBOED net. We are continuing work to hook up the Alder module to the Britannia facilities and anticipate delivery of first gas in 2016. Alder is a high-pressure, high-temperature gas condensate reservoir located in the U.K. Continental Shelf, 17 miles west of the Britannia facilities.

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.

We have various ownership interests in several producing gas fields in the Rotliegendes and Carboniferous areas of the Southern North Sea. Decommissioning activity in the Southern North Sea is ongoing, with final production from the Viking transportation system and associated satellites achieved in early 2016. Our interests in the East Irish Sea include the Millom, Dalton and Calder fields, which are operated on our behalf by a third party.

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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 2018.

Exploration

During 2015, we participated in a nonoperated exploration/appraisal well in the Greater Clair area which was a discovery. The discovery is undergoing evaluations for future development. We also drilled one operated exploration well north of the Jasmine Field in the Central Graben which was a dry hole, and were awarded two new licenses in the East Irish Sea.

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.

Greenland

Exploration

In 2015, 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 and geological and geophysical studies as part of the work program obligation in the nonoperated Avinngaq license. In the fourth quarter of 2015, we initiated the process to assign our participating interest in the Avinngaq license. The process is pending Greenland government approval.

Libya

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 was shut in again. The Es Sider Terminal remained shut in throughout 2015. The 2016 operating and drilling activity is uncertain as a result of the ongoing civil unrest.

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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 and Australia; producing operations in Qatar and Timor-Leste; and exploration activities in Brunei. In 2015, operations in the Asia Pacific and Middle East segment contributed 13 percent of our worldwide liquids production and 33 percent of natural gas production.

Australia and Timor Sea

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 sold to domestic customers, while LNG is exported. Origin operates APLNG’s upstream production and pipeline system, and we operate the downstream LNG facility, located on Curtis Island near Gladstone, Queensland, as well as the LNG export sales business.

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. APLNG Train 1 achieved first LNG in the fourth quarter of 2015 and the first cargo sailed in January 2016. Train 1 LNG is being sold to Sinopec under a 20-year sales agreement for up to 4.3 million metric tonnes of LNG per year. Start-up of the second LNG train is expected to occur in the second half of 2016. 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 $8.4 billion had been drawn from the facility at December 31, 2015. 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 4—Variable Interest Entities (VIEs), Note 7—Investments, Loans and Long-Term Receivables, and Note 12—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 310-mile natural gas pipeline connects the facility to the 3.5 million tonnes-per-year capacity Darwin LNG Facility. Produced natural gas is

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piped to the Darwin LNG Plant, where it is converted into LNG before being transported to international markets. In 2015, we sold 174 billion gross cubic feet of LNG primarily 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. The first subsea, horizontal well commenced production in the first quarter of 2015. The well was tied back to the existing drilling, production, and processing platform. A second subsea, horizontal well was drilled, completed, then suspended due to insufficient deliverability to the platform. There are no plans to remediate nor re-drill the well in the near

future. A continuation of Phase Three development is being evaluated, and is currently in the preliminary front-end engineering and design phase.

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. In January 2016, the Government of Timor-Leste and ConocoPhillips reached a settlement of several significant tax disputes. However, we await the Tribunal’s decision with respect to certain unresolved matters. For additional information, see Note 13—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 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 five additional discoveries: Boreas-1, Zephyros-1, Proteus-1 SD2, Poseidon-North-1 and Pharos-1. All wells have been completed, plugged and abandoned.

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, containing the Barossa and Caldita discoveries. Three appraisal wells have been drilled to further evaluate the Barossa Field’s potential. The first two wells encountered hydrocarbons and the third was not commercially viable.

In 2015, regulatory approval was received to withdraw from the four exploration permits within the Canning Basin in Western Australia. Prior to withdrawal, we owned a 46 percent working interest in each of the four permits.

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Indonesia

We operate four production sharing contracts (PSCs) in Indonesia: the offshore South Natuna Sea Block B and three onshore PSCs, the Corridor Block and South Jambi “B”, both located in South Sumatra, and Kualakurun in Central Kalimantan. Currently there is production from two of these PSCs: the Corridor Block and South Natuna Sea Block B.

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.

Exploration

In 2015, we drilled and subsequently recorded dry hole expense for one exploration well in the Palangkaraya PSC. This PSC was relinquished in the third quarter of 2015. We are also in the process of relinquishing our 80 percent interest in the Warim Block PSC. We have a 60 percent working interest in the new Kualakurun PSC, located in Central Kalimantan, which was signed in May 2015. This block has an area of approximately 2 million gross acres.

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.

China

The Penglai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05. Production from the Phase 1 development of the Penglai 19-3 Field began in 2002. Phase 2 included six additional wellhead platforms and an FPSO vessel, and was fully operational by 2009.

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Currently, a project to add a new wellhead platform and up to 62 wells for the development of Penglai 19-9 is progressing per schedule, with first oil expected in 2017.

We sanctioned the Penglai 19-3/19-9 Phase 3 Project in December 2015. This project will consist of three new wellhead platforms and a central processing platform. First oil from Phase 3 is expected in 2018.

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 working interest in the block.

Exploration

In 2015, we participated in two successful appraisal wells in the Penglai fields, which will be used to support future development plans.

Malaysia

We own interests in four deepwater PSCs in Malaysia. Three are located off the eastern Malaysian state of Sabah: Block G, Block J and the Kebabangan Cluster (KBBC). Our fourth PSC, deepwater Block 3E, is located off the Malaysian state of Sarawak.

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 and reached its estimated net annual peak production of 5 MBOED in 2015. Development of the Malikai oil field is underway with first production anticipated in 2017. We own a 35 percent interest in the Malikai and Pisagan discoveries.

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 32 MBOED anticipated in 2016. Unitization of the Gumusut Field with Brunei was recorded in 2014 and reduced our ownership interest from 33 percent to an initial 29 percent. A final ownership split is expected to be agreed in 2016.

We own a 40 percent interest in the Limbayong discovery. 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.

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. Gas sales are currently constrained due to repairs on a third party pipeline. Estimated net annual peak production of 26 MBOED is expected in 2018. Kamunsu East is being evaluated for development options.

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Exploration

We relinquished our 40 percent operating interest in SB-311, an exploration block encompassing 259,000 gross acres offshore Sabah, in December 2015. Both wells drilled in 2015 as part of our two-well commitment program were expensed as dry holes in the second and third quarters of 2015.

We own a 50 percent operating interest in deepwater Block 3E, which encompasses approximately 480,000 gross acres offshore Sarawak. Seismic processing was completed in 2015 and drilling is planned for 2016-2017.

Bangladesh

Exploration

In 2014, we relinquished our interest in two deepwater blocks in the Bay of Bengal, Blocks 10 and 11. In 2015, we also opted not to pursue our interest in three adjoining deepwater blocks and exited operations in Bangladesh.

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, with natural gas discovered at the Kelidang NE-1 and Keratau-1 wells in 2013 and at the Keratau SW-1 well in 2015. Evaluation of the results is ongoing.

Myanmar

Exploration

In 2014, we were awarded deepwater Block AD-10 in the 2013 Myanmar offshore oil and gas bidding round. We signed the PSC in the second quarter of 2015, and in the third quarter we initiated the process to assign our participating interest to the operator, pending Myanmar government approval.

Qatar

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 is combined and shared.

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OTHER INTERNATIONAL

The Other International segment includes exploration activities in Colombia, Angola and Senegal. In the fourth quarter of 2015, we exited our operations in Russia. During 2015, operations in Other International contributed less than 1 percent of our worldwide liquids production.

Russia

Polar Lights

In the fourth quarter of 2015, we completed the sale of our 50 percent interest in the Polar Lights Company, 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 and each block was awarded with a two-well work program commitment. We 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, located in Block 36 offshore Angola, as a dry hole. We also subsequently plugged and abandoned the Omosi-1 and Vali-1 wells as dry holes in adjacent Block 37 in the first and second quarters of 2015, respectively, and recorded an after-tax impairment of $75 million associated with our Angola Block 37 leasehold in the second quarter of 2015. In the fourth quarter of 2015, we recorded $335 million in after-tax charges for the impairment, dry hole costs and future potential obligations associated with our Angola Block 36 leasehold. The Athena drilling rig, secured for our four-well commitment program, was mobilized to Senegal in October.

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. We spud the SNE-2 and SNE-3 appraisal wells in the fourth quarter of 2015. 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. In the fourth quarter of 2015, we finalized the sale of our 2.5 percent interest in BTC.

Poland

Exploration

In the second quarter of 2015, we decided not to conduct further activity on our three Baltic Basin concessions, which encompassed approximately 500,000 gross acres. As a result, we recorded an after-tax impairment of $32 million, net of other deductions.

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Colombia

Unconventional Exploration

We have an 80 percent operated interest in the Middle Magdalena Basin block VMM-3. The block extends over 66,649 net acres and contains the Picoplata-1, which completed drilling in 2015. Continued evaluation and testing of the well is planned in 2016.

We hold 70 percent nonoperated interests in the deep rights in the Santa Isabel Block in the Middle Magdalena Basin, which covers approximately 71,000 net acres. We also hold a 30 percent nonoperated interest in the VMM27 and VMM28 blocks, in the Middle Magdalena Basin, which are currently in the process of being relinquished.

Chile

Exploration

In the fourth quarter of 2015, we received approval from the Chilean government to become a 5 percent interest holder in the Coiron Block. Empresa Nacional del Petroleo holds the remaining 95 percent interest and is the operator of the block.

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). The ICSID Tribunal 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 13—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 to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims followed the decision on liability and we are now waiting for the Tribunal’s award. For additional information, see Note 13—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Discontinued Operations

See Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements, for information regarding our discontinued operations.

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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 and sell third-party volumes to better position the company to satisfy customer demand while fully utilizing transportation and storage capacity.

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.

LNG

LNG marketing efforts are focused on equity LNG production facilities located in Alaska, Australia, and Qatar. LNG is primarily sold under long-term contracts with prices based on market indices.

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 industry has been relying on since 2011. Equipment from both systems has been combined to form MWCC’s 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.

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.

Oil Spill Response Removal Organizations (OSROs)

We maintain memberships in several OSROs across the globe as a key element of our preparedness program in addition to internal response resources. Many of the OSROs are not-for-profit cooperatives owned by the member companies wherein we may actively participate as a member of the board of directors, steering committee, work group or other supporting role. Globally, our primary OSRO is Oil Spill Response Ltd. based in the U.K., with facilities in several other countries and the ability to respond anywhere in the world. In North America, our primary OSROs include the Marine Spill Response Corporation for the continental U.S. and Alaska Clean Seas and Ship Escort/Response Vessel System for the Alaska North Slope and Prince

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William Sound, respectively. We are also a member of the Cook Inlet Spill Prevention and Response, Inc. Internationally, we maintain memberships in various regional OSROs including the Norwegian Clean Seas Association for Operating Companies, Australian Marine Oil Spill Center and Petroleum Industry of Malaysia Mutual Aid Group.

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, 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 be successful with the demand for new LNG plants. The technology has been licensed for use in 25 LNG trains around the world, with feasibility studies ongoing for additional trains.

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, 2015. No difference exists between our estimated total proved reserves for year-end 2014 and year-end 2013, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2015.

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 2.5 trillion cubic feet of natural gas, including approximately 430 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 230 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 7, 2015, 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 2014. 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.

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GENERAL

At the end of 2015, we held a total of 1,012 active patents in 58 countries worldwide, including 387 active U.S. patents. During 2015, we received 46 patents in the United States and 85 foreign patents. Our products and processes generated licensing revenues of $271 million in 2015. 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 $222 million, $263 million and $258 million in 2015, 2014 and 2013, 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 process and occupational safety. In support of the goal of zero incidents, HSE milestones and criteria are established annually to drive strong safety performance. Progress toward these milestones and criteria are measured and reported. HSE audits are conducted on business functions periodically, and improvement actions are established and tracked to completion. 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 62 through 66 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2015 and those expected for 2016 and 2017.

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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Item 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.

Our operating results, our future rate of growth and the carrying value of our assets are exposed to the effects of changing commodity prices.

Prices for crude oil, bitumen, natural gas, natural gas liquids and LNG can fluctuate widely. Globally, prices for crude oil, bitumen, natural gas, natural gas liquids and LNG have recently experienced significant declines from their historic levels during 2013 and 2014, with continued global production increases that have outpaced demand growth, leading to a large observed rise in global inventory. Prices for Brent crude oil, WTI crude oil, Henry Hub natural gas and natural gas liquids in the fourth quarter of 2015 have all declined more than 40 percent when compared with prices in the fourth quarter of 2014, and there are no indications the price declines will reverse themselves in the immediate future.

Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil, bitumen, natural gas, natural gas liquids and LNG. The factors influencing these prices are beyond our control. Lower crude oil, bitumen, natural gas, natural gas liquids and LNG prices may have a material adverse effect on our revenues, operating income, cash flows and liquidity and on the amount of dividends we elect to declare and pay on our common stock. Lower prices may also limit the amount of reserves we can produce economically, adversely affecting our ability to maintain our reserve replacement ratio and accelerating the reduction in our existing reserve levels as we continue production from upstream fields.

Significant reductions in crude oil, bitumen, natural gas, natural gas liquids and LNG prices could also require us to reduce our capital expenditures or impair the carrying value of our assets. During 2015, we recognized several impairments, which are described in Note 9—Impairments, in the Notes to Consolidated Financial Statements. If commodity prices remain low relative to their historic levels, and as we continue to optimize our investments and exercise capital flexibility, it is reasonably likely we will incur future impairments to long-lived assets used in operations, investments in nonconsolidated entities accounted for under the equity method and unproved properties. Although it is not reasonably practicable to quantify the impact of any future impairments at this time, our results of operations could be adversely affected as a result.

Our ability to declare and pay dividends is subject to certain considerations.

Dividends are authorized and determined by our Board of Directors in its sole discretion and depend upon a number of factors, including:

We expect to continue to pay quarterly distributions to our stockholders; however, we bear all expenses incurred by our operations, and our funds generated by operations, after deducting these expenses, may not be sufficient to cover desired levels of distributions to our stockholders. Any downward revision in our distribution could have a material adverse effect on the market price of our common stock.

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We may need additional capital in the future, and it may not be available on acceptable terms.

We have historically relied primarily upon cash generated by our operations to fund our operations and strategy, however we have also relied from time to time on access to the debt and equity capital markets for funding. There can be no assurance that additional debt or equity financing will be available in the future on acceptable terms, or at all. Our ability to obtain additional financing will be subject to a number of factors, including market conditions, our operating performance, investor sentiment and our ability to incur additional debt in compliance with agreements governing our then-outstanding debt. If we are unable to generate sufficient funds from operations or raise additional capital, our growth could be impeded.

In addition, we are regularly evaluated by the major rating agencies based on a number of factors, including our financial strength and conditions affecting the oil and gas industry generally. Due to the significant recent decline in prices for crude oil, bitumen, natural gas, natural gas liquids and LNG, and the expectation that these prices could remain depressed in the near future, the major ratings agencies have indicated they will be conducting a review of the oil and gas industry and the debt ratings for some companies operating in the industry may be downgraded. The results of these actions, including any downgrade in our credit rating, could increase the cost associated with any additional indebtedness we incur.

Our business may be adversely affected by deterioration in the credit quality of, or defaults under our contracts with, third parties with whom we do business.

The operation of our business requires us to engage in transactions with numerous counterparties operating in a variety of industries, including other companies operating in the oil and gas industry. These counterparties may default on their obligations to us as a result of operational failures or a lack of liquidity, or for other reasons, including bankruptcy. Market speculation about the credit quality of these counterparties, or their ability to continue performing on their existing obligations, may also exacerbate any operational difficulties or liquidity issues they are experiencing, particularly as it relates to other companies in the oil and gas industry as a result of the recent significant declines in commodity prices. Any default by any of our counterparties may result in our inability to perform obligations under agreements we have made with third parties or may otherwise adversely affect our business or results of operations. In addition, our rights against any of our counterparties as a result of a default may not be adequate to compensate us for the resulting harm caused or may not be enforceable at all in some circumstances.

Unless we successfully add to our existing proved reserves, our future crude oil, bitumen, natural gas and natural gas liquids production will decline, resulting in an adverse impact to our business.

The rate of production from upstream fields generally declines as reserves are depleted. Except to the extent that we conduct successful exploration and development activities, or, through engineering studies, optimize production performance or identify additional or secondary recovery reserves, our proved reserves will decline materially as we produce crude oil, bitumen, natural gas and natural gas liquids. Accordingly, to the extent we are unsuccessful in replacing the crude oil, bitumen, natural gas and natural gas liquids we produce with good prospects for future production, our business will experience reduced cash flows and results of operations. Any cash conservation efforts we may undertake as a result of commodity price declines may further limit our ability to replace depleted reserves.

Any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural gas and natural gas liquids reserves could impair the quantity and value of those reserves.

Our proved reserve information included in this annual report has been derived from engineering estimates prepared by our personnel. Reserve estimation is a process that involves estimating volumes to be recovered from underground accumulations of crude oil, bitumen, natural gas and natural gas liquids that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of reserves and future net cash flows based on the same available data. Any significant future price changes could have a material effect on the quantity and present value of our proved reserves. Any material changes in the factors and assumptions

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underlying our estimates of these items could result in a material negative impact to the volume of reserves reported or could cause us to incur impairment expenses on property associated with the production of those reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation. In addition to changes in the quantity and value of our proved reserves, the amount of crude oil, bitumen, natural gas and natural gas liquids that can be obtained from any proved reserve may ultimately be different from those estimated prior to extraction.

We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations, such as limitations on greenhouse gas emissions, may impact or limit our current business plans and reduce demand for our products.

Our businesses are subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.

Although our business operations are designed and operated to accommodate expected climatic conditions, to the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall. Demand for our products may also be adversely affected by conservation plans and efforts undertaken in response to global climate change, including plans developed in connection with the recent Paris climate conference in December 2015. Many governments also provide, or may in the future provide, tax advantages and other subsidies to support the use and development of alternative energy technologies. Our operations and the demand for our products could be materially impacted by the development and adoption of these technologies.

Domestic and worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows.

Actions of the U.S., state, local and foreign governments, through tax and other legislation, executive order and commercial restrictions, could reduce our operating profitability both in the United States and abroad. In certain locations, governments have imposed or proposed restrictions on our operations; special taxes or tax assessments; and payment transparency regulations that could require us to disclose competitively sensitive information or might cause us to violate non-disclosure laws of other countries. U.S. federal, state and local legislative and regulatory agencies’ initiatives regarding the hydraulic fracturing process could result in operating restrictions or delays in the completion of our oil and gas wells.

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The U.S. government can also prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries. Actions by host governments have affected operations significantly in the past, such as the expropriation of our oil assets by the Venezuelan government, and may continue to do so in the future. Changes in domestic and international regulations may affect our ability to obtain or maintain permits, including those necessary for drilling and development of wells or for construction of LNG terminals or regasification facilities in various locations.

Local political and economic factors in international markets could have a material adverse effect on us. Approximately 54 percent of our hydrocarbon production from continuing operations was derived from production outside the United States in 2015, and 61 percent of our proved reserves, as of December 31, 2015, was located outside the United States. We are subject to risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas, bitumen, natural gas liquids or LNG pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations. In particular, some countries where we operate lack well-developed legal systems or have not adopted clear legal and regulatory frameworks for oil and gas exploration and production. This lack of legal certainty exposes our operations to increased risks, including increased difficulty in enforcing our agreements in those jurisdictions and increased risks of adverse actions by local government authorities, such as expropriations.

Changes in governmental regulations may impose price controls and limitations on production of crude oil, bitumen, natural gas and natural gas liquids.

Our operations are subject to extensive governmental regulations. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil, bitumen, natural gas and natural gas liquids wells below actual production capacity. Because legal requirements are frequently changed and subject to interpretation, we cannot predict the effect of these requirements.

Our investments in joint ventures decrease our ability to manage risk.

We conduct many of our operations through joint ventures in which we may share control with our joint venture partners. There is a risk our joint venture participants may at any time have economic, business or legal interests or goals that are inconsistent with those of the joint venture or us, or our joint venture partners may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

We do not insure against all potential losses; therefore, we could be harmed by unexpected liabilities and increased costs.

We maintain insurance against many, but not all, potential losses or liabilities arising from operating risks. As such, our insurance coverage may not be sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations present hazards and risks that require significant and continuous oversight.

The scope and nature of our operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, crude oil spills, severe weather, geological events, labor disputes, terrorist attacks, sabotage, civil unrest or cyber attacks. Our operations may also be adversely affected by unavailability, interruptions or accidents involving services or infrastructure required to develop, produce, process or transport our production, such as contract labor, drilling rigs, pipelines, railcars, tankers, barges or other infrastructure. Our operations are subject to the additional hazards of pollution, releases of toxic gas and

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other environmental hazards and risks. Activities in deepwater areas may pose incrementally greater risks because of complex subsurface conditions such as higher reservoir pressures, water depths and metocean conditions. All such hazards could result in loss of human life, significant property and equipment damage, environmental pollution, impairment of operations, substantial losses to us and damage to our reputation. Further, our business and operations may be disrupted if we do not respond, or are perceived not to respond, in an appropriate manner to any of these hazards and risks or any other major crisis or if we are unable to efficiently restore or replace affected operational components and capacity.

Our technologies, systems and networks may be subject to cybersecurity breaches. Although we have experienced occasional, actual or attempted breaches of our cybersecurity, none of these breaches has had a material effect on our business, operations or reputation. If our systems for protecting against cybersecurity risks prove to be insufficient, we could be adversely affected by having our business systems compromised, our proprietary information altered, lost or stolen, or our business operations disrupted. As cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information systems and related infrastructure security vulnerabilities.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the fourth quarter of 2015, as well as matters previously reported in our 2014 Form 10-K and our first-, second- and third-quarter 2015 Form 10-Qs that were not resolved prior to the fourth quarter of 2015. Material developments to the previously reported matters have been included in the descriptions below. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were to be decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to SEC regulations.

On April 30, 2012, the separation of our downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters, such as legal proceedings. We have included matters where we remain a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim against us.

Matters Previously Reported—Phillips 66

In October 2007, ConocoPhillips received a Complaint from the U.S. Environmental Protection Agency (EPA) alleging violations of the Clean Water Act related to a 2006 oil spill at the Phillips 66 Bayway Refinery and proposing a penalty of $156,000.

On May 19, 2010, the Phillips 66 Lake Charles Refinery received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations, as well as certain provisions of the consent decree in Civil Action No. H-01-4430. In July 2014, Phillips 66 resolved the consent decree issues and in January 2016, an agreement was reached with LDEQ to resolve the remaining allegations.

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On October 15, 2012, the Bay Area Air Quality Management District (Bay Area AQMD) issued a $313,000 demand to settle 13 other Notice of Violation (NOV) issued in 2010 and 2011 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

In May 2012, the Illinois Attorney General’s office filed and notified ConocoPhillips of a complaint with respect to operations at the Phillips 66 WRB Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party’s hazardous waste permit. The complaint seeks as relief remediation of area groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures; additional spill reporting; and yet-to-be specified amounts for fines and penalties.

On July 7, 2014, Phillips 66 received an NOV from the U.S. EPA alleging various flaring-related violations between 2009 and 2013 at the Phillips 66 Wood River Refinery. ConocoPhillips is not a named party in the NOV and we will therefore no longer report this matter.

On July 8, 2014, the Bay Area AQMD issued a $175,000 demand to settle 18 NOVs issued in 2010 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

On July 8, 2014, the Bay Area AQMD issued a $259,000 demand to settle 20 NOVs issued in 2011 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

Not applicable.

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EXECUTIVE OFFICERS OF THE REGISTRANT

*On February 15, 2016.

There are no family relationships among any of the officers named above. Each officer of the company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the company holds office from the date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 10, 2016. Set forth below is information about the executive officers.

Janet L. Carrig was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary in 2007.

Ellen R. DeSanctis was appointed Vice President, Investor Relations and Communications in May 2012. She was previously employed by Petrohawk Energy Corp. and served as Senior Vice President, Corporate Communications since 2010. Prior to that she was employed by Rosetta Resources Inc. and served as Executive Vice President of Strategy and Development from 2008 to 2010.

Matt J. Fox was appointed Executive Vice President, Exploration and Production in May 2012. Prior to that, he was employed by Nexen, Inc. and served as Executive Vice President, International since 2010. He was previously employed by ConocoPhillips and served as President, ConocoPhillips Canada from 2009 to 2010.

Alan J. Hirshberg was appointed Executive Vice President, Technology and Projects in May 2012. Prior to that, he served as Senior Vice President, Planning and Strategy since 2010.

Ryan M. Lance was appointed Chairman of the Board of Directors and Chief Executive Officer in May 2012, having previously served as Senior Vice President, Exploration and Production—International since May 2009.

Andrew D. Lundquist was appointed Senior Vice President, Government Affairs in 2013. Prior to that, he served as managing partner of BlueWater Strategies LLC, since 2002.

James D. McMorran was appointed Vice President, Human Resources, Real Estate and Facilities Services in August 2015. Prior to that, he served as Manager, Compensation and Benefits, since 2004.

Glenda M. Schwarz was appointed Vice President and Controller in 2009.

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Jeff W. Sheets was appointed Executive Vice President, Finance and Chief Financial Officer in May 2012, having previously served as Senior Vice President, Finance and Chief Financial Officer since 2010.

Don E. Wallette, Jr. was appointed Executive Vice President, Commercial, Business Development and Corporate Planning in May 2012. Prior to that, he served as President, Asia Pacific since 2010 and President, Russia/Caspian from 2006 to 2010.

On February 16, 2016, Jeff W. Sheets announced his decision to retire as Executive Vice President, Finance and Chief Financial Officer. Mr. Sheets will remain in his position as Executive Vice President, Finance and Chief Financial Officer until April 1, 2016, and following that will remain an employee through May 31, 2016, to provide support during the transition of his responsibilities.

In connection with Mr. Sheets’ retirement, at a meeting held on February 16 and 17, 2016, the Board of Directors approved the following changes to our executive leadership team to become effective April 1, 2016:

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PART II

Quarterly Common Stock Prices and Cash Dividends Per Share

ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”

*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency listing.

The declaration of dividends is subject to the discretion of our Board of Directors, and may be affected by various factors, including our future earnings, financial condition, capital requirements, levels of indebtedness, credit ratings and other considerations our Board of Directors deems relevant. Our Board of Directors has adopted a quarterly dividend declaration policy providing that the declaration of any dividends will be determined quarterly by the Board of Directors taking into account such factors as our business model, prevailing business conditions and our financial results and capital requirements, without a predetermined annual net income payout ratio.

On February 4, 2016, we announced that our Board of Directors approved a reduction in the quarterly dividend to $0.25 per share, compared with the previous quarterly dividend of $0.74 per share. The dividend is payable on March 1, 2016 to stockholders of record at the close of business on February 16, 2016.

Issuer Purchases of Equity Securities

During 2015, there were no active share repurchase programs and no repurchases of common stock from employees in connection with the company’s broad-based employee incentive programs.

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Item 6.     SELECTED FINANCIAL DATA

Net income (loss) and Net income (loss) attributable to ConocoPhillips for all periods presented includes income from discontinued operations as a result of the separation of the downstream business, the sale of our interest in Kashagan, and the sales of our Algeria and Nigeria businesses. These factors impact the comparability of this information. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

See Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Notes to Consolidated Financial Statements for a discussion of factors that will enhance an understanding of this data.

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Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 72.

Due to discontinued operations reporting, income (loss) from continuing operations is more representative of ConocoPhillips’ earnings. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have operations and activities in 21 countries. At December 31, 2015, we employed approximately 15,900 people worldwide and had total assets of $97.5 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Basis of Presentation

Effective November 1, 2015, the Other International and historically presented Europe segments were restructured to align with changes to our internal organization structure. The Libya business was moved from the Other International segment to the historically presented Europe segment, which is now renamed Europe and North Africa. Accordingly, results of operations for the Other International and Europe and North Africa segments have been revised in all periods presented. There was no impact on our consolidated financial statements, and the impact on our segment presentation is immaterial. For additional information, see Note 24—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements.

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. Our diverse portfolio primarily includes resource-rich North American unconventional assets and oil sands assets in Canada; lower-risk legacy assets in North America, Europe, Asia and Australia; several major international developments; and an inventory of global conventional and unconventional exploration prospects.

The energy landscape changed dramatically in the past year. Increased supply caused commodity prices to decline substantially. In December 2015, we announced a 2016 operating plan based on $7.7 billion of capital expenditures. This represented a reduction of 24 percent, compared to 2015 actual expenditures, sourced from the completion of several major projects, as well as deferrals, deflation capture and efficiencies across the portfolio.

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In response to an outlook of lower prices in 2016 compared to 2015, as well as credit tightening across the industry, we revised our 2016 operating plan in February 2016, reducing our capital expenditures guidance by 17 percent, from $7.7 billion to $6.4 billion. We also reduced our quarterly dividend by 66 percent, to $0.25 per share. These actions, taken to maintain a strong balance sheet, will enable us to continue to deliver an investment offering of a competitive dividend, disciplined growth and financial strength. We also believe these actions position the company for success in a lower, more volatile price environment, with the flexibility to adjust to commodity price movements in the future.

Key Operating and Financial Summary

Significant items during 2015 included the following:

We accomplished several strategic milestones in 2015. Excluding Libya, our production from continuing operations was 1,589 MBOED, compared with 1,532 MBOED in 2014, a 57 MBOED increase. The production increase was driven by growth from major projects and development programs, as well as improved well performance, partially offset by normal field decline. In 2015, we generated $2 billion from the disposition of certain non-core assets in our portfolio. The full-year 2015 production impact of completed dispositions was 64 MBOED.

In 2015, we reviewed our cost structure and took decisive actions to achieve sustainable operating cost reductions across the company. We targeted a $1 billion reduction in operating costs in 2016, compared with 2014. We reduced headcount, including management positions, to streamline decision-making, increased the autonomy in our business units, captured deflation and adjusted our activity levels, which resulted in achieving our stated target in 2015, a year ahead of schedule. Operating costs include production and operating expense; selling, general and administrative expense; and exploration expense excluding dry hole and leasehold impairment expense.

We generated $7.6 billion in cash from continuing operations in 2015, paid dividends on our common stock of $3.7 billion and ended the year with $2.4 billion in cash and cash equivalents.

Business Environment

In the first half of 2014, strong crude oil prices were supported by geopolitical tensions impacting supplies, as well as global oil demand growth. This was followed by an abrupt decline in prices during the fourth quarter of 2014, as surging production growth from U.S. tight oil and the decision by the Organization of Petroleum Exporting Countries (OPEC) to maintain production outweighed fears of supply disruptions. These developments, combined with slowing global oil demand growth, caused crude oil prices to plummet to near five-year lows at the end of 2014. Prices remained significantly lower throughout 2015, reaching a ten-year quarterly low of $43.67 for Brent crude oil, in the fourth quarter of 2015. Lower 2015 prices contributed to higher demand growth which was overwhelmed by continued production increase and supply surplus. Brent crude oil was $30.69 in January 2016, reflecting an ongoing decline in prices.

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The energy industry has periodically experienced this type of extreme volatility due to fluctuating supply-and-demand conditions. Commodity prices are the most significant factor impacting our profitability and related reinvestment of operating cash flows into our business. Among other dynamics that could influence world energy markets and commodity prices are global economic health, supply disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by OPEC, environmental laws, tax regulations, governmental policies and weather-related disruptions. North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, primarily due to advances in technology responsible for the rapid growth of tight oil production, successful exploration and rising production from the Canadian oil sands. Our strategy is to sustainably lower our cost structure and maintain a strong balance sheet and a diverse low cost-of-supply portfolio that can provide the financial flexibility to withstand challenging business cycles.

Operating and Financial Priorities

Other important factors we must continue to manage well in order to be successful include:

We are a founding member of the Marine Well Containment Company LLC (MWCC), a non-profit organization formed in 2010 to improve industry spill response in the U.S. Gulf of Mexico. MWCC developed a 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 complement this work internationally, we and several leading oil and gas companies established the Subsea Well Response Project in Norway, which enhances the oil industry’s ability to respond to subsea well-control incidents in international waters.

In February 2016, we announced a revised capital budget of $6.4 billion for 2016, a reduction of 37 percent compared with actual capital expenditures of $10.1 billion in 2015. The $3.7 billion reduction primarily reflects lower spending on major projects, deferral of activity primarily in the Lower 48, deflation capture and efficiencies across the portfolio.

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In 2015, we generated approximately $2 billion in proceeds from non-core asset dispositions, including the sales of certain western Canadian properties, producing properties in East Texas and North Louisiana, producing properties in South Texas, a certain pipeline and gathering assets in South Texas, and our 50 percent equity method investment in the Russian joint venture, Polar Lights Company. We will continue to evaluate our assets to determine whether they fit our strategic direction and will optimize the portfolio as necessary, directing our capital investments to areas that align with our objectives.

Proved reserve estimates require economic production based on historical 12-month, first-of-month, average prices and current costs. Therefore, our proved reserves generally decrease as prices decline and increase as prices rise. Additionally, as we undertake cash conservation efforts, our reserve replacement efforts could be delayed thus limiting our ability to replace depleted reserves. Low commodity prices and reduced capital expenditures in 2015 adversely affected our reported year-end proved reserves. In 2015, our organic reserve replacement excluding the impact of sales and purchases was 10 percent. In the five years ended December 31, 2015, our organic reserve replacement was 117 percent, excluding the impact of sales and purchases.

Access to additional resources has become increasingly difficult as commodity prices can make projects uneconomic or unattractive. In addition, prohibition of direct investment in some nations, national fiscal terms, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.

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Other significant factors that can affect our profitability include:

Crude oil prices have remained under pressure throughout 2015 due to continued global production increase that has outpaced demand growth, leading to a large observed rise in global inventory. Brent crude oil prices averaged $43.67 per barrel in the fourth quarter of 2015, a decrease of 43 percent compared with $76.27 per barrel in the fourth quarter of 2014. Similarly, WTI crude oil prices declined 43 percent from $73.41 per barrel in the fourth quarter of 2014 to $42.10 per barrel in the same period of 2015.

Henry Hub natural gas prices averaged $2.27 per million British thermal units (MMBTU) in the fourth quarter of 2015, a decrease of 44 percent compared with $4.04 per MMBTU in the fourth quarter of 2014. Natural gas prices remained under pressure as production growth continued and U.S. underground gas storage inventories rose to the top of the five-year range in late 2015.

Natural gas liquids prices were also lower in 2015. Our realized natural gas liquids prices averaged $16.42 per barrel in the fourth quarter of 2015, a decrease of 47 percent compared with $31.07 per barrel in the same quarter of 2014. The expansion in tight oil production has also helped boost supplies of natural gas liquids, resulting in continued downward pressure on natural gas liquids prices in the United States.

Declining global crude oil prices have resulted in the Western Canada Select benchmark price experiencing a 52 percent decline, from $73.60 per barrel in 2014 to $35.21 per barrel in 2015. Consequently, our realized bitumen price experienced a decrease relative to 2014 price levels. Our realized bitumen price was $18.72 per barrel in 2015, a decrease of 66 percent compared with $55.13 in the same period of 2014.

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Our total average realized price from continuing operations was $34.34 per barrel of oil equivalent (BOE) in 2015, a decrease of 47 percent compared with $64.59 per BOE in 2014. Our total average realized price was $28.54 per BOE in the fourth quarter of 2015, a decrease of 46 percent compared with $52.88 per BOE in the fourth quarter of 2014. The reduction in the prices reflects lower average realized prices across all commodities.

In recent years, the use of hydraulic fracturing and horizontal drilling in tight oil formations has led to increased industry actual and forecasted crude oil and natural gas production in the United States. Although providing significant short- and long-term growth opportunities for our company, the increased abundance of crude oil and natural gas due to development of tight oil plays could also have adverse financial implications to us, including: an extended period of low commodity prices; production curtailments; delay of plans to develop areas such as unconventional fields or Alaska North Slope natural gas fields; and underutilization of LNG regasification facilities. Should one or more of these events occur, our revenues would be reduced and additional asset impairments might be possible.

Going forward, domestic crude prices should reach a market equilibrium with global crude prices due to the recent overturn of the U.S. crude export bans.

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Outlook

Consistent with our revised 2016 operating plan announced in February 2016, our full-year 2016 production from continuing operations is expected to be flat with 2015 production of 1,525 MBOED, which excludes 64 MBOED for the full-year impact of completed dispositions. First-quarter 2016 production from continuing operations is expected to be 1,540 MBOED to 1,580 MBOED.

Marketing Activities

In line with our objective to continuously optimize our portfolio, we are currently marketing certain non-core assets. We expect to generate up to $1 billion in proceeds annually from asset sales.

Impairments

As a result of lower commodity prices, and as we optimize our investments and exercise capital flexibility, it is reasonably likely we may incur future impairment charges to long-lived assets used in operations, investments in nonconsolidated entities accounted for under the equity method, and unproved properties. Although it is not reasonably practicable to quantify the impact of future impairment charges at this time, our results of operations could be materially adversely affected for the period in which impairment charges are incurred.

Operating Segments

We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska, Lower 48, Canada, Europe and North Africa, Asia Pacific and Middle East, and Other International.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, certain technology activities, as well as licensing revenues received.

Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our continuing operations, including commodity prices and production.

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RESULTS OF OPERATIONS

Consolidated Results

A summary of the company’s income (loss) from continuing operations by business segment follows:

2015 vs. 2014

Earnings for ConocoPhillips decreased 175 percent in 2015. The decrease was mainly due to lower commodity prices.

In addition, earnings were negatively impacted by:

These reductions to earnings were partly offset by higher sales volumes, lower production taxes due to reduced commodity prices, lower operating expenses, a $555 million net deferred tax benefit resulting from a change in the U.K. tax rate in the first quarter of 2015, the absence of a $540 million after-tax loss resulting from the Freeport LNG termination agreement, gain on sale of assets, and higher licensing revenue.

2014 vs. 2013

Earnings for ConocoPhillips decreased 28 percent in 2014. The decrease was mainly due to:

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These reductions to earnings were partially offset by higher volumes; lower production taxes, which mainly resulted from higher capital spending, lower prices and lower production volumes in Alaska; and higher natural gas and LNG prices.

Income Statement Analysis

2015 vs. 2014

Sales and other operating revenues decreased 44 percent in 2015, mainly as a result of lower prices across all commodities. Lower prices were partly offset by higher crude oil and LNG sales volumes.

Equity in earnings of affiliates decreased 74 percent in 2015. The decrease was primarily due to lower earnings from FCCL Partnership and Qatar Liquefied Gas Company Limited (3) (QG3), given lower commodity prices, partly offset by higher volumes and lower operational costs.

Gain on dispositions increased by $493 million in 2015. The increase resulted from a $583 million gain from the sales of producing properties in East Texas and North Louisiana, South Texas, and a certain pipeline and gathering assets in South Texas. Gains realized were partly offset by a net loss from the disposition of non-core assets in western Canada. For additional information on gains on dispositions, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Other income decreased 66 percent in 2015, mainly due to the absence of 2014 income related to the resolution of a contingent liability in the Other International segment and a legal arbitration settlement in Asia Pacific and Middle East, respectively.

Purchased commodities decreased 44 percent in 2015, largely as a result of lower natural gas prices and the absence of a $130 million loss in the Lower 48 related to transportation and storage capacity agreements recognized in 2014.

Production and operating expenses decreased 21 percent in 2015, largely due to lower operating expense activity, including reduced turnarounds at our Bayu-Undan Field and Darwin LNG facility, favorable foreign exchange-related impacts, and the absence of an $849 million charge resulting from the Freeport LNG termination agreement in 2014. The decrease in expense was partially offset by restructuring expenses of $206 million in 2015.

Selling, general and administrative (SG&A) expenses increased 30 percent in 2015, primarily due to $407 million in restructuring and pension settlement expenses in 2015, partially offset by lower staff and compensation plan costs.

Exploration expenses increased 105 percent in 2015, mainly as a result of higher unproved property impairments, primarily in Alaska, Angola and the Lower 48. Higher dry hole and other exploration costs, including a $253 million pre-tax expense for wells charged to dry hole in Canada, a $383 million expense related to the termination of our Gulf of Mexico deepwater drillship contract, and a $176 million charge for two wells charged to dry hole in the Gila prospect in the deepwater Gulf of Mexico, also contributed to the increase in exploration expenses. For additional information on leasehold impairments and other exploration expenses, see Note 8—Suspended Wells and Other Exploration Expenses, and Note 9—Impairments, in the Notes to Consolidated Financial Statements.

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DD&A increased 9 percent in 2015. The increase was mainly associated with higher production volumes in the Lower 48 and Asia Pacific and Middle East and commodity price-related reserve revisions. The increase was partly offset by reserve additions in the Lower 48.

Impairments increased 162 percent in 2015. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 57 percent in 2015, mainly due to lower production taxes from reduced commodity prices in the Lower 48, Alaska and Asia Pacific and Middle East.

Interest and debt expense increased 42 percent in 2015, primarily due to lower capitalized interest on projects and increased average debt levels in 2015.

See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

2014 vs. 2013

Sales and other operating revenues decreased 3 percent in 2014, mainly as a result of lower crude oil prices, partly offset by higher crude oil and bitumen volumes and higher natural gas prices.

Equity in earnings of affiliates increased 14 percent in 2014, primarily as a result of higher earnings from FCCL Partnership due to higher bitumen volumes and prices. This increase was partially offset by lower earnings from APLNG, mostly as a result of higher operating expenses and DD&A.

Gain on dispositions decreased $1,144 million in 2014. Gains realized in 2014 mostly resulted from the disposition of certain properties in western Canada. For additional information on gains realized in prior years, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Production and operating expenses increased 23 percent in 2014, largely due to the $849 million charge resulting from the Freeport LNG termination agreement. Higher drilling and maintenance activity, mostly in the Lower 48, Australia, Alaska and Europe, in addition to the absence of the 2013 benefit of a $142 million accrual reduction related to the Federal Energy Regulatory Commission (FERC) approval of cost allocation (pooling) agreements with the remaining owners of the Trans-Alaska Pipeline System (TAPS), also contributed to the increase. These increases were partly offset by the absence of a $155 million charge in 2013 related to Bohai Bay. For additional information on the Freeport LNG transaction, see Note 7—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.

SG&A expenses decreased 14 percent in 2014, mainly due to the absence of pension settlement expenses.

Exploration expenses increased 66 percent in 2014, mainly as a result of higher impairments of undeveloped leasehold costs, primarily in the Lower 48 and Canada, and higher dry hole costs, mostly associated with the Gulf of Mexico and Angola. For additional information on the leasehold impairments, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

DD&A increased 12 percent in 2014. This increase was mostly associated with higher production volumes in the United Kingdom and the Lower 48, partly offset by lower unit-of-production rates in Canada associated with year-end 2013 price-related reserve revisions and lower natural gas production volumes.

Impairments increased 62 percent in 2014. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

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Taxes other than income taxes decreased 28 percent in 2014, mainly due to lower production taxes, which resulted from higher capital spending, lower crude oil prices and lower production volumes in Alaska.

Interest and debt expense increased 6 percent in 2014, primarily due to lower capitalized interest on projects, partly offset by lower interest expense from lower average debt levels and a $28 million benefit associated with interest on a favorable tax settlement.

See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

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Excludes discontinued operations.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2015, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia and Qatar.

Total production from continuing operations, including Libya, increased 3 percent in 2015. The increase in total average production in 2015 primarily resulted from additional production from major developments, including tight oil plays in the Lower 48; Gumusut in Malaysia; APLNG in Australia; Greater Britannia projects and the J-Area in the U.K.; and the ramp-up of Foster Creek Phase F in Canada. Improved well performance, mostly in the Lower 48, western Canada and Norway, and lower turnaround activity also contributed to higher production in 2015. These increases were largely offset by normal field decline. Adjusted for downtime and dispositions of 13 MBOED, our production from continuing operations, excluding Libya, increased by 70 MBOED, or 5 percent, compared with 2014. Full-year 2015 production from assets sold or under agreement was 64 MBOED.

In 2014, average production from continuing operations increased 3 percent compared with 2013, while average liquids production increased 4 percent. The increase in total average production in 2014 primarily resulted from additional production from major developments, mainly from tight oil 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. Adjusted for Libya, production from continuing operations increased by 60 MBOED, or 4 percent, compared with 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. In 2015, Alaska contributed 19 percent of our worldwide liquids production and 1 percent of our natural gas production.

2015 vs. 2014

Alaska reported earnings of $4 million in 2015, compared with earnings of $2,041 million in 2014, mainly due to lower commodity prices and a $368 million after-tax charge in the fourth quarter of 2015 for the impairment of our Chukchi Sea leasehold and capitalized interest. The earnings decrease was partly offset by reduced production taxes resulting from lower commodity prices.

Average production decreased 3 percent in 2015 compared with 2014, primarily due to normal field decline, partly offset by lower planned downtime activity and new production from the Western North Slope, Greater Prudhoe and Greater Kuparuk areas.

2014 vs. 2013

Alaska earnings decreased 10 percent in 2014 compared with 2013 earnings. The decrease was largely due to lower crude oil prices and volumes; the absence of a $97 million after-tax benefit associated with a FERC ruling in 2013, more fully described below; higher operating expenses; and a $36 million after-tax impairment related to a cancelled project. These reductions to earnings were partly offset by lower production taxes, which resulted from higher 2014 capital spending and lower crude oil prices and volumes. Higher LNG sales volumes and prices also partially offset the decrease in 2014 earnings.

In 2012, the major owners of TAPS filed a proposed settlement with FERC to resolve pooling disputes prior to August 2012 and establish a voluntary pooling agreement to pool costs prospectively from August 2012. In July 2013, FERC approved the proposed settlement and pooling agreement without modification. As a result, we reduced a related accrual in the second quarter of 2013, which decreased our production and operating expenses by $97 million after-tax.

Average production decreased 9 percent in 2014 compared with 2013, mainly as a result of normal field decline and higher planned maintenance, partly offset by lower unplanned downtime.

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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. During 2015, the Lower 48 contributed 33 percent of our worldwide liquids production and 36 percent of our natural gas production.

2015 vs. 2014

Lower 48 reported a loss of $1,932 million after-tax in 2015, compared with a loss of $22 million after-tax in 2014. The decrease in earnings was primarily due to:

These decreases were partly offset by the absence of a $545 million after-tax charge resulting from the Freeport LNG termination agreement in 2014; a $368 million after-tax gain from the disposition of certain properties in South Texas, East Texas and Northern Louisiana; higher volumes; lower production taxes; and the absence of a $151 million after-tax impairment charge resulting from reduced volume forecasts on proved properties and the associated undeveloped leasehold costs.

Our average realized prices in the Lower 48 have historically correlated with WTI prices; however, beginning in the second half of 2013, our Lower 48 crude differential versus WTI began to widen. Our 2015 average realized crude oil price of $42.62 per barrel was 13 percent less than WTI of $48.72 per barrel. The differential is driven primarily by local market dynamics in the Gulf Coast, Bakken and the Permian Basin, and may remain relatively wide in the near-term.

Total average production increased 2 percent in 2015 compared with 2014, while average crude oil production increased 10 percent across the same period. The increase was mainly attributable to new production, primarily from Eagle Ford, Bakken and the Permian Basin, partially offset by normal field decline.

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2014 vs. 2013

The Lower 48 reported a loss of $22 million after-tax in 2014, compared with earnings of $754 million after-tax in 2013. The decrease in earnings was primarily attributable to:

These reductions to earnings were partially offset by higher crude oil and natural gas liquids volumes, higher natural gas prices and a benefit to earnings of approximately $150 million after-tax from marketing third-party natural gas volumes.

Total average production in the Lower 48 increased 9 percent in 2014, while average crude oil production increased 24 percent. The increase was mainly attributable to new production, primarily from the Eagle Ford and Bakken, and improved drilling and well performance, partially offset by normal field decline.

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Canada