CONOCOPHILLIPS - Annual Report: 2016 (Form 10-K)

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2016

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended         December 31, 2016                                             

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, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $43.60, was $54.0 billion.

The registrant had 1,235,832,469 shares of common stock outstanding at January 31, 2017.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 16, 2017 (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 the applicable periods presented. For additional information on the sale of our Nigeria business, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Headquartered in Houston, Texas, we have operations and activities in 17 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 conventional assets in North America, Europe, Asia and Australia; several liquefied natural gas (LNG) developments; and an inventory of global conventional and unconventional exploration prospects.

At December 31, 2016, ConocoPhillips employed approximately 13,300 people worldwide.

In November 2016, we announced our planned $5 billion to $8 billion asset disposition program, primarily associated with North American natural gas assets, over the next two years. 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

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, LNG and natural gas liquids on a worldwide basis. At December 31, 2016, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.

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

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The following table is a summary of the proved reserves information included in the “Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements. Approximately 81 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.

Total production, including Libya, of 1,569 thousand barrels of oil equivalent per day (MBOED) decreased 1 percent in 2016 compared with 2015. The decrease in total average production primarily resulted from normal field decline and the loss of 72 MBOED mainly attributable to the 2015 dispositions of several non-core assets in the Lower 48, western Canada and the sale of our interest in the Polar Lights Company in Russia. The decrease in production was partly offset by additional production from major developments, including tight oil plays in the Lower 48; APLNG in Australia; the Western North Slope in Alaska; the Kebabangan gas field in Malaysia; and the Greater Ekofisk Area in Norway. Improved drilling and well performance in Canada, Norway, the Lower 48, and China, as well as lower unplanned downtime in the Lower 48 also partly offset the decrease in production. Assets sold in 2016 produced 27 MBOED and 36 MBOED in 2016 and 2015, respectively.

Our worldwide annual average realized price was $28.35 per BOE in 2016, a decrease of 17 percent compared with $34.34 per BOE in 2015, which reflected lower average realized prices across all commodities. Our worldwide annual average crude oil price decreased 15 percent in 2016, from $48.26 per barrel in 2015 to $40.86 per barrel in 2016. Additionally, our worldwide annual average natural gas liquids prices decreased 6 percent, from $17.79 per barrel in 2015 to $16.68 per barrel in 2016. Our worldwide annual average natural gas price decreased 24 percent, from $3.96 per MCF in 2015 to $3.00 per MCF in 2016. Average annual bitumen prices also decreased 18 percent, from $18.72 per barrel in 2015 to $15.27 per barrel in 2016.

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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 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, federal and fee exploration leases, with approximately 0.5 million net undeveloped acres at year-end 2016. Following the impairment of our Chukchi Sea leases in the fourth quarter of 2015, we surrendered 0.3 million acres in the Chukchi Sea in May 2016. In 2016, Alaska operations contributed 19 percent of our worldwide liquids production and less than 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, Lisburne and North Prudhoe Bay State 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, and completion of the first phase of the project was achieved 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 2018.

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 National Petroleum Reserve-Alaska (NPR-A). During the year, we approved drilling an additional 18 wells, bringing CD5 up to its full permit capacity.

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The Greater Mooses Tooth Unit, the first unit established entirely within the NPR-A, was formed in 2008. In 2017, we began construction in the unit, which is currently planned to have two drill sites; Greater Mooses Tooth #1 and #2, with expected first oil in 2018 and 2020, respectively.

Cook Inlet Area

We have a 100 percent interest and are the operator of the Kenai LNG Facility in the Cook Inlet Area. 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. In February 2016, our export license was renewed for an additional two years. However, there was no LNG export program in 2016 due to market conditions. We are currently marketing this facility.

In April and October 2016, we sold our interests in the Beluga River Unit natural gas field and the North Cook Inlet Unit, respectively, both in the Cook Inlet Area. The full-year 2016 production from the assets sold was 2 MBOED.

Point Thomson

We own a 4.9 percent interest in the Point Thomson Unit, which is located approximately 60 miles east of Prudhoe Bay. An Initial Production System (IPS) was brought online in April 2016, and achieved full production of 400 BOED net of condensate in December.

Alaska North Slope Gas

In 2016, we, along with affiliates of Exxon Mobil Corporation, BP p.l.c. and Alaska Gasline Development Corporation (AGDC), a state-owned corporation (collectively, the “AKLNG co-venturers”), completed preliminary front-end engineering and design (pre-FEED) technical work for a potential LNG project which would liquefy and export natural gas from Alaska’s North Slope and deliver it to market. In September 2016, we, along with the affiliates of ExxonMobil and BP, indicated our intention not to progress into the next phase of the project due to changes in the economic environment. Given AGDC’s intention to continue efforts to advance a North Slope Gas project, the AKLNG co-venturers executed certain agreements to enhance AGDC’s ability to do so. We remain supportive of AGDC’s efforts to progress a project.

Exploration

In 2016, we drilled three exploration wells in the NPR-A. Two of these wells, Tinmiaq 2 and 6, form the Willow discovery, which is located in the northeast portion of the NPR-A. The third exploration well was recorded to dry hole expense in the fourth quarter of 2016. Appraisal of the Willow discovery commenced in January 2017 with the acquisition of 3-D seismic. In a follow-up to the Willow discovery, we were successful in December’s state and federal lease sales on the Western North Slope, where we were the high bidder on 139 tracts for a total of 737,252 gross acres.

Transportation

We transport the petroleum liquids produced on the North Slope to south central Alaska through an 800-mile pipeline that is part of Trans-Alaska Pipeline System (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 deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the United States.

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LOWER 48

The Lower 48 segment consists of operations located in the U.S. Lower 48 states and 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. We have subsequently terminated our Gulf of Mexico deepwater drillship contracts. We hold 12.4 million net onshore and offshore acres in the Lower 48. In 2016, the Lower 48 contributed 30 percent of our worldwide liquids production and 32 percent of our natural gas production.

Onshore

We hold 12.3 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:

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The majority of our 2016 onshore production originated from the Eagle Ford, San Juan, Permian and Bakken. Onshore activities in 2016 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 2016 drilling activity levels declined relative to 2015 due to reduced capital spending in the low commodity price environment. Our major focus areas in 2016 included the following:

In 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. In the second quarter of 2016, we completed the sale of certain non-core assets in the Delaware basin. The full-year 2016 production from the assets sold was 1 MBOED.

Gulf of Mexico

At year-end 2016, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one operated field and three fields operated by co-venturers, including:

Exploration

At December 31, 2016, we held approximately 73,000 net acres in the deepwater Gulf of Mexico.

We own a 30 percent nonoperated working interest in the Shenandoah discovery, which was announced in 2009, and had a net book value of $286 million at December 31, 2016. Appraisal drilling continued in 2016 with the fifth Shenandoah well reaching total depth in the third quarter. In February 2017, the sixth Shenandoah well, Shenandoah WR52-3, reached total depth. Drilling of a sidetrack well from Shenandoah WR52-3 also commenced in February.

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As part of our continued phased exit from deepwater exploration, in 2016, we decided not to pursue further development of the nonoperated Gibson and Tiber wells, collectively known as the Tigris project. Accordingly, we recorded dry hole expenses for previously suspended Gibson and Tiber wells, and impairment charges for the applicable leaseholds.

We recorded dry hole and associated leasehold impairment expense in the first quarter of 2016 for the Melmar exploration well.

In 2016, we drilled a total of five operated unconventional wells, primarily in the Eagle Ford. Our onshore focus areas include the Permian in the Delaware Basin and the Niobrara in the Denver-Julesburg Basin, as well as several emerging plays. We continue to assess and appraise these 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 was reduced to zero on July 1, 2016. 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 $260 million at December 31, 2016. 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.

Greater Northern Iron Ore Properties Trust

We held the reversionary interest in the Greater 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. On November 3, 2016, the end of the wind-down period, documents memorializing our ownership of certain Trust property, including all the Trust’s mineral properties and active leases, were delivered to us. The $144 million fair value of the Trust’s net assets transferred to us and a gain of $88 million were both recorded in the fourth quarter of 2016. On December 8, 2016, we closed on a sale of the Trust’s and certain other assets for net proceeds of $148 million. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Other

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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 2016, operations in Canada contributed 23 percent of our worldwide liquids production and 14 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 30 natural gas processing plants in the region, and, as of December 31, 2016, held leasehold rights in 3.1 million net acres in western Canada. Our investments in 2016 were focused mainly on opportunities in the following three core development areas:

Oil Sands

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. We hold approximately 0.9 million net acres of land in the Athabasca Region of northeastern Alberta.

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Foster Creek is located approximately 200 miles northeast of Edmonton, Alberta. With the achievement of first production at Phase G in 2016, there are seven producing phases at Foster Creek, Phases A through G. Net production at Foster Creek increased approximately 5 MBOED in 2016.

Christina Lake is located approximately 75 miles south of Fort McMurray, Alberta. Christina Lake Phase F achieved first production in 2016. There are now six producing phases at Christina Lake. Construction on Phase G, which has a design capacity of 50 MBOED gross, will resume in 2017 after being deferred since 2014. First production from Phase G is expected in the second half of 2019. Net production at Christina Lake increased approximately 6 MBOED in 2016.

Narrows Lake Phase A, was sanctioned in late 2012 and is expected to have 45 MBOED of gross design production capacity. Construction has been deferred, however, we expect to progress engineering activity in 2017.

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.

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 2016, we recorded dry hole expenses associated with two wells in the Shelburne Basin, and an impairment charge for the undeveloped leasehold costs. Other related costs have been accrued.

In August 2016, we sold our Newfoundland Partnership, which held a 30 percent nonoperated interest in the exploration license in the Flemish Pass Basin, offshore Newfoundland.

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 2016, we completed a lease swap for unproved lands in the Blueberry area and continued to drill exploration and appraisal wells in the Montney play, which extends from British Columbia into Alberta. Full-year 2016 production from the assets swapped was 5 MBOED. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

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EUROPE AND NORTH AFRICA

The Europe and North Africa segment consists of operations and exploration activities in Norway, the United Kingdom and Libya. In 2016, 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, some gas is exported to the Continent via gas processing terminals in Norway, while the remainder is exported for use 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.

Exploration

We participated in two nonoperated exploration wells in the Oseberg and Alvheim areas. Both wells were discoveries and are currently undergoing evaluation. We were awarded three licenses in 2016, including the PL845 and PL782SB, both with interests of 40 percent, and PL859, which has a 15 percent interest.

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.

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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, Brodgar, Enochdhu and Alder, produce via subsea manifolds and pipelines linked to the Britannia platform. Project startups for the Brodgar H3 susbsea well, and Enochdhu, a single well tie back to Callanish, were achieved in 2015. First gas was achieved from Alder, a single well tie back to Britannia, in the fourth quarter of 2016.

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.

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

In 2016, we recorded dry hole expense for the fully-owned Temple Wood well in the Greater Britannia Area, which was permanently plugged and abandoned.

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.

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Greenland

Exploration

In the first quarter of 2016, we completed the process to assign our participating interest in the nonoperated Avinngaq license. Additionally, our operated Qamut license expired on December 31, 2016. Our work program in Greenland is complete, pending certain approvals.

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. Production resumed in Libya in October 2016, with three crude liftings from Es Sider in January 2017. We expect a gradual ramp-up in activity.

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 2016, operations in the Asia Pacific and Middle East segment contributed 14 percent of our worldwide liquids production and 42 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 coalbed methane 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.

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Two fully subscribed 4.5 million tonnes-per-year LNG trains have been completed. Approximately 3,900 net wells are ultimately envisioned to supply both the domestic gas market and the LNG sales contracts. The wells are supported by gathering systems, central gas processing and compression stations, water treatment facilities, and an export pipeline connecting the gas fields to the LNG facilities. The first APLNG Train 1 cargo sailed in January 2016, and LNG sales continued throughout the year. 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. APLNG Train 2 achieved first production in the third quarter of 2016. The LNG from Train 2 is being sold to Sinopec under a 20-year sales agreement for an additional 3.3 million metric tonnes of LNG per year through 2035, and Japan-based Kansai Electric Power Co., Inc. under a 20-year sales agreement for approximately 1 million metric tonnes of LNG per year.

APLNG has an $8.5 billion project finance facility, of which $8.5 billion had been drawn from the facility at December 31, 2016. 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. In October 2016, we reached financial completion for Train 1, which reduced our associated guarantee by 60 percent. 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 piped to the Darwin LNG Plant, where it is converted into LNG before being transported to international markets. In 2016, we sold 168 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 was tied back to the existing drilling, production and processing platform, and commenced production in 2015, while the second well was suspended due to insufficient deliverability to the platform. A continuation of the Bayu-Undan Phase Three Development is being evaluated with the front-end engineering and design phase approaching completion. The current premise is that drilling of one subsea and two platform wells will commence in 2018, pending internal, joint venture and regulatory approval.

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 Singapore in June 2014 under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste government. We reached a settlement with the Timor-Leste government on these disputes in 2016.

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 April 2016, the Timor-Leste Government initiated conciliation under the United Nations Convention of the Law of the Sea (UNCLOS) in an attempt to negotiate permanent maritime boundaries. The conciliation is on-going between the governments of Timor-Leste and Australia.

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The UNCLOS conciliation 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 three exploration permits in the Browse Basin, offshore northwest Australia, in which we own a 40 percent interest in permits WA-315-P, WA-398-P and TP 28, of the Greater Poseidon Area. The TP 28 Western Australia State exploration permit was granted for five years from January 2017, with a 40 percent working interest and was excised from the existing permits as agreed between state and federal regulators. 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. A new 3-D seismic survey was completed over the Barossa and Caldita Field area between August and October 2016. Drilling of the next appraisal well, Barossa-5, commenced in January 2017. Drilling of a subsequent well, Barossa-6, may follow dependent on the results of Barossa-5.

Indonesia

We operate three production sharing contracts (PSCs) in Indonesia: The Corridor Block and South Jambi “B,” both located in South Sumatra, and Kualakurun in Central Kalimantan. Currently there is production from the Corridor Block. In 2016, we sold our 40 percent working interest in the offshore South Natuna Sea Block B PSC, which had 3 producing oil fields, and 16 natural gas fields in various stages of development. Full-year 2016 production from South Natuna Sea Block B was 19 MBOED.

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

During 2016, we relinquished our 80 percent interest in the Warim Block PSC. We have a 60 percent working interest in the 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.

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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.

As part of further development of the Penglai 19-9 Field, a new wellhead platform, which adds up to 62 wells, is progressing according to schedule, with two wells completed and brought online in December 2016.

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 production period for Panyu 4-2 and 5-1 will expire in 2018, and the production period for Panyu 11-6 will expire in 2022.

Exploration

In 2016, we participated in a successful appraisal well in the Penglai fields, which will support future development plans.

Malaysia

We own interests in six PSCs in Malaysia. Three are located off the eastern Malaysian state of Sabah: Block G, Block J and the Kebabangan Cluster (KBBC). Three other blocks, deepwater Block 3E, Block SK313 and Block WL4-00 are located off the eastern Malaysian state of Sarawak.

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Block G

We have a 21 percent interest in the unitized Siakap North-Petai oil field, which began producing in the first quarter of 2014 and reached its estimated net annual peak production of 5 MBOED in 2015.

First production from Malikai was achieved in December 2016, with estimated net annual peak production of 18 MBOED expected in 2019. The Limbayong-1 well was drilled in 2002 and resulted in a gas discovery. The Limbayong-2 appraisal well was drilled in 2013 and resulted in an oil discovery. Development options are being evaluated. We own a 35 percent interest in the Malikai, Limbayong 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 net annual peak production of 36 MBOED reached 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 2017. Gumusut Phase 2 infill drilling is planned to start in 2018.

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. Estimated net annual peak production of 26 MBOED is expected in 2018. Development options for the Kamunsu East gas field are being evaluated.

Exploration

We own a 50 percent operated interest in deepwater Block 3E, which encompasses approximately 480,000 gross acres offshore Sarawak. Seismic processing was completed in 2015. The Langsat-1 exploration well was spud in February 2017.

In the fourth quarter of 2016, we entered into a farm-in agreement to acquire a 50 percent interest in Block SK 313, a 1.4 million gross-acre exploration block, effective January 2017. Following completion of the Sadok-1 exploration well in January 2017, we assumed operatorship of the block from PETRONAS.

We were awarded Block WL4-00, which encompasses approximately 629,000 gross acres, in January 2017. We have a 50 percent operated interest in this block which includes the Salam-1 oil discovery. A new 3-D seismic survey is planned for 2017 with drilling of an appraisal well expected in 2018.

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. In 2016, we assigned our participating interest to the operator.

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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.

OTHER INTERNATIONAL

The Other International segment includes exploration activities in Colombia and Chile. In 2016, we sold ConocoPhillips Senegal B.V., the entity that held our 35 percent interest in three exploration blocks offshore Senegal.

Angola

Exploration

Our 50 percent operated interest in Block 36 and our 30 percent operated interest in Block 37, both of which are located in Angola’s subsalt play trend, expired on December 31, 2016. In February 2017, we reached a settlement agreement on our contract for the Athena drilling rig, initially secured for our four-well commitment program in Angola. As a result of the cancellation, we will recognize a before-tax charge of $43 million net in the first quarter of 2017.

Senegal

Exploration

On October 28, 2016, we sold ConocoPhillips Senegal B.V., the entity that held our 35 percent interest in three exploration blocks offshore Senegal. See Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for information regarding our asset dispositions.

Colombia

Unconventional Exploration

We have an 80 percent operated interest in the Middle Magdalena Basin Block VMM-3. The block extends over approximately 67,000 net acres and contains the Picoplata-1 well, which completed drilling in 2015. Production tests and appraisal of the area are ongoing.

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. The relinquishment of the Santa Isabel Block was accepted and the parties are in the process of documenting such relinquishment.

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The exploration and production contract for the VMM27 Block, in the Middle Magdalena Basin, where we held a 30 percent nonoperated interest, has been fully terminated. We also hold a 30 percent nonoperated interest in the VMM28 Block, in the Middle Magdalena Basin, where we are in the process of terminating with the relevant parties and the regulatory agency.

Chile

Exploration

In June 2016, we entered into an agreement with Empresa Nacional Del Petroleo (ENAP) to acquire an additional 44 percent participating interest in the onshore Coiron Block located in the Magallanes Basin in southern Chile where we already had 5 percent participation. Assignment of the additional participating interest to ConocoPhillips was approved by the Chilean Ministry of Energy and the Controller General of Chile. ENAP holds the remaining 51 percent participating interest and will continue to be the operator.

In 2016, two exploration wells were successfully drilled, logged and cored. In 2017, we will continue to explore and appraise the Coiron 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. In October 2016, ConocoPhillips brought fraudulent transfer actions in the U.S. District Court of Delaware against PDVSA, alleging that PDVSA has taken actions to improperly expatriate assets from the United States to Venezuela in an effort to avoid judgment creditors. 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. In February 2017, the tribunal unanimously awarded Burlington $380 million for Ecuador’s unlawful expropriation and breach of the U.S.-Ecuador bilateral investment treaty. The tribunal also issued a separate decision finding Ecuador to be entitled to $42 million for limited environmental and infrastructure impacts associated with the operations of Burlington and its co-venturer. Ecuador recently filed a request for annulment of this decision with ICSID. The schedule for the annulment process has not yet been set. 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.

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.

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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 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. MWCC’s containment system 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. For additional information, see Note 4—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

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 William Sound, respectively. 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

We have several technology programs that improve our ability to develop unconventional reservoirs, produce heavy oil economically with fewer emissions, improve the efficiency of our company’s exploration program, increase recoveries from our legacy fields, and implement 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.

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RESERVES

We have not filed any information with any other federal authority or agency with respect to our estimated total proved reserves at December 31, 2016. No difference exists between our estimated total proved reserves for year-end 2015 and year-end 2014, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2016.

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 2.0 trillion cubic feet of natural gas, including approximately 363 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 180 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2027. 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 5, 2016, 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 2015. We deliver our production into the worldwide commodity markets. Principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; economic analysis in connection with portfolio management; and safely operating oil and gas producing properties.

GENERAL

At the end of 2016, we held a total of 714 active patents in 49 countries worldwide, including 286 active U.S. patents. During 2016, we received 37 patents in the United States and 66 foreign patents. Our products and processes generated licensing revenues of $128 million in 2016. 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 $116 million, $222 million and $263 million in 2016, 2015 and 2014, 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.

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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 63 through 66 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2016 and those expected for 2017 and 2018.

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 experienced significant declines from their historic levels during 2013 and 2014, with excess of supply relative to global demand leading to global inventory builds. Total average annual prices in 2016 for Brent crude oil, WTI crude oil, Henry Hub natural gas and our realized natural gas liquids all decreased by more than 5 percent when compared with 2015. In the fourth quarter of 2016, Brent crude oil, WTI crude oil, Henry Hub natural gas and our realized natural gas liquids prices all increased, compared with the same period of 2015. Given volatility in commodity price drivers and the business environment, price trends may not continue or reverse themselves.

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. In the past two years, we recognized several impairments, which are described in Note 9—Impairments and the “APLNG” section of Note 7—Investments, Loans and Long-Term Receivables, 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 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 conducted a review of the oil and gas industry and downgraded our debt ratings and those of several companies operating in the industry. 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.

The exploration and production of oil and gas is a highly competitive industry.

The exploration and production of crude oil, bitumen, natural gas and natural gas liquids is a highly competitive business. We compete with private, public and state-owned companies in all facets of the exploration and production business, including to locate and obtain new sources of supply and to produce oil, bitumen, natural gas and natural gas liquids in an efficient, cost-effective manner. Some of our competitors are larger and have greater resources than we do or may be willing to incur a higher level of risk than we are willing to incur to obtain potential sources of supply. If we are not successful in our competition for new reserves, our financial condition and results of operations may be adversely affected.

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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 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 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.

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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.

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 58 percent of our hydrocarbon production was derived from production outside the United States in 2016, and 55 percent of our proved reserves, as of December 31, 2016, 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.

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We may not be able to successfully complete any disposition we elect to pursue.

From time to time, we may seek to divest portions of our business or investments that are not important to our ongoing strategic objectives. Any dispositions we undertake may involve numerous risks and uncertainties, any of which could adversely affect our results of operations or financial condition. In particular, we may not be able to successfully complete any disposition on a timeline or on terms acceptable to us, if at all, whether due to market conditions, regulatory challenges or other concerns. In addition, the reinvestment of capital from disposition proceeds may not ultimately yield investment returns in line with our internal or external expectations. Any dispositions we pursue may also result in disruption to other parts of our business, including through the diversion of resources and management attention from our ongoing business and other strategic matters, or through the disruption of relationships with our employees and key vendors. Further, in connection with any disposition, we may enter into transition services agreements or undertake indemnity or other obligations that may result in additional expenses for us.

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 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.

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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 2016, as well as matters previously reported in our 2015 Form 10-K and our first-, second- and third-quarter 2016 Form 10-Qs that were not resolved prior to the fourth quarter of 2016. 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 or have subsequently become 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.

New Matters—ConocoPhillips

A Judgment and Consent Decree was entered on December 7, 2016, by the South Central Judicial District Court in Burleigh County, North Dakota against Burlington Resources Oil & Gas Company LP and ConocoPhillips Company resolving alleged violations of the state’s air pollution control laws. The North Dakota Department of Health was the Plaintiff in this matter. The Consent Decree requires the companies to implement a specified program to inspect and repair as necessary its facilities in North Dakota and to pay a penalty of approximately $220,000.

Matters Previously Reported—Phillips 66

In October 2007, we 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 Bayway Refinery and proposing a penalty of $156,000. Phillips 66 resolved this matter with the EPA in December 2016 with a settlement payment of $35,500.

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.

New Matters—Phillips 66

In October 2016, after Phillips 66 received a Notice of Intent to Sue from the Sierra Club, Phillips 66 entered into a voluntary settlement with the Illinois Environmental Protection Agency for alleged violations of wastewater requirements at the Wood River Refinery occurring in part prior to the separation. The settlement involves certain capital projects and payment of $125,000. The settlement has been filed with the Court for final approval and the Sierra Club has sought to intervene in the case to oppose the settlement. A court hearing is scheduled for March 2017.

Not applicable.

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EXECUTIVE OFFICERS OF THE REGISTRANT

*On February 15, 2017.

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 16, 2017. 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 as Executive Vice President, Strategy, Exploration and Technology in April 2016. He previously served as the Executive Vice President, Exploration and Production, from 2012 to 2016. Prior to that, he was employed by Nexen, Inc. and served as Executive Vice President, International since 2010.

Alan J. Hirshberg was appointed Executive Vice President, Production, Drilling and Projects in April 2016. He previously served as Executive Vice President, Technology and Projects, from 2012 to 2016. 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.

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

Don E. Wallette, Jr. was appointed Executive Vice President, Finance, Commercial and Chief Financial Officer in April 2016. He previously served as Executive Vice President, Commercial, Business Development and Corporate Planning from 2012 to 2016. Prior to that, he served as President, Asia Pacific since 2010 and President, Russia/Caspian from 2006 to 2010.

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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.”

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.

On January 31, 2017, we announced that our Board of Directors approved an increase in the quarterly dividend to $0.265 per share, compared with the previous quarterly dividend of $0.25 per share.

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Issuer Purchases of Equity Securities

*There were no repurchases of common stock from company employees in connection with the company’s broad-based employee incentive plans.

On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock over the next three years. Repurchase of shares began in November and totaled 2,579,098 shares at a cost of $126 million, through December 31, 2016. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

Stock Performance Graph

The following graph shows the cumulative total shareholder return (TSR) for ConocoPhillips’ common stock in each of the five years from December 31, 2011, to December 31, 2016. The graph also compares the cumulative total returns for the same five-year period with the S&P 500 Index, the performance peer group used in the prior fiscal year (the “Prior Peer Group”) and a new performance peer group for the current fiscal year (the “New Peer Group”). The Prior Peer Group consisted of BP, Chevron, ExxonMobil, Royal Dutch Shell, Total, Anadarko, Apache, BG Group plc, Devon and Occidental, weighted according to the respective peer’s stock market capitalization at the beginning of each annual period. The New Peer Group excludes BG Group plc due to its acquisition by Royal Dutch Shell in 2016 and includes Marathon Oil Corporation. The Prior Peer Group is presented for purposes of comparison. The comparison assumes $100 was invested on December 31, 2011, in ConocoPhillips stock, the S&P 500 Index, the Prior Peer Group and New Peer Group and assumes that all dividends were reinvested. The spinoff of Phillips 66 in 2012 is treated as a special dividend for the purposes of calculating TSR for ConocoPhillips. The market value of the distributed shares on the spinoff date was deemed reinvested in shares of ConocoPhillips common stock.

  *Prior Peer Group: BP; Chevron; ExxonMobil; Royal Dutch Shell; Total; Anadarko; Apache; BG Group plc; Devon; Occidental.

**New Peer Group: BP; Chevron; ExxonMobil; Royal Dutch Shell; Total; Anadarko; Apache; Marathon Oil Corporation; Devon; Occidental.

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Item 6.     SELECTED FINANCIAL DATA

Net income (loss) and Net income (loss) attributable to ConocoPhillips from 2012 to 2014 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 on the sale of our Nigeria business, 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, we believe income (loss) from continuing operations is more representative of ConocoPhillips’ earnings than overall net income (loss) attributable to ConocoPhillips. 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 17 countries. Our diverse portfolio primarily includes resource-rich North American unconventional assets and oil sands assets in Canada; lower-risk conventional assets in North America, Europe, Asia and Australia; several liquefied natural gas (LNG) developments; and an inventory of global conventional and unconventional exploration prospects. At December 31, 2016, we employed approximately 13,300 people worldwide and had total assets of $90 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Overview

The energy landscape remained challenged throughout 2016. Global production oversupply caused continued weakness in commodity prices in 2016 following a year of weak prices in 2015. Ongoing uncertainty around the timing and trajectory of a price recovery, coupled with tightening credit capacity across the industry, caused us to take actions early in the year to mitigate the impacts of possible prolonged weak prices. We reduced our quarterly dividend by 66 percent, to $0.25 per share, issued $3.0 billion of long-term debt, obtained a $1.6 billion three-year term loan, reduced capital expenditures and production and operating expenses, and further streamlined our portfolio.

Our capital expenditures in 2016 were $4.9 billion, a 52 percent reduction compared with 2015 and a 72 percent reduction compared with 2014. Production and operating expenses in 2016 were $5.7 billion, down 19 percent compared with 2015 and down 36 percent compared with 2014.

We also progressed our efforts to high-grade our portfolio. In 2016, we generated $1.3 billion from the disposition of certain non-core assets in our portfolio, including the offshore South Natuna Sea Block B in Indonesia and ConocoPhillips Senegal B.V., the entity that held our interest in three exploration blocks offshore Senegal. The full-year 2016 production impact of completed dispositions was 27 thousand barrels of oil equivalent per day (MBOED).

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During 2016, we expanded our value proposition to position the company for long-term success in light of our view that commodity prices, specifically oil prices, are likely to remain lower and be more volatile in the future. Our value proposition principles, namely to maintain a strong balance sheet, grow our dividend and pursue disciplined growth, remain essentially unchanged. However, we took steps to improve our competitiveness and resilience by establishing clear priorities for allocating future cash flows.

In order, these priorities are: invest capital at a level that maintains flat production volumes and pays our existing dividend; grow our existing dividend; reduce debt to a level we believe is sufficient to maintain a strong investment grade rating through price cycles; repurchase shares; and invest capital to grow absolute production. We outlined a 2017 to 2019 operating plan that achieves these priorities at Brent prices at or above $50 per barrel with asset sales of $5 billion to $8 billion.

We believe we have taken prudent actions to position the company for success in an environment of price uncertainty and ongoing volatility, while accomplishing significant milestones in a challenged business environment throughout 2016.

Key Operating and Financial Summary

Significant items during 2016 included the following:

Business Environment

Global oil market conditions in 2016 were challenging as the excess of supply relative to global demand led to another year of global inventory builds. Global oil prices experienced elevated levels of volatility throughout 2016 with first quarter Brent crude oil prices reaching a 10-year quarterly average low of $33.89 per barrel. Prices recovered slightly in the second and third quarters of 2016 as production growth slowed while demand continued to increase. In the fourth quarter, prices continued to trend higher, with Brent crude oil averaging $49.46 per barrel, as OPEC members and key non-OPEC producers agreed to cut production in 2017.

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 create value through price cycles by delivering on the financial and operational priorities that underpin our value proposition.

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Financial Priorities

The financial priorities we believe will drive our success through the price cycles include:

Operational Priorities

The operational priorities we must manage well to be successful include:

In November 2016, we announced a 2017 capital budget of $5 billion.

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In November 2016, we announced our plan to divest between $5 billion and $8 billion of assets, primarily associated with North American natural gas, over the next two years. Proceeds from the sale of assets will be directed toward the achievement of our financial priorities. 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 continue 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 2016 adversely affected our reported year-end proved reserves. In 2016, our reserve replacement was negative 194 percent. In the five years ended December 31, 2016, our reserve replacement was 35 percent. We expect our proved reserves to increase if prices rise.

Access to additional resources may 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 Factors Affecting Profitability

Other significant factors that can affect our profitability include:

Brent crude oil prices averaged $49.46 per barrel in the fourth quarter of 2016, an increase of 13 percent compared with $43.67 per barrel in the fourth quarter of 2015. Similarly, WTI crude oil prices increased 17 percent from $42.10 per barrel in the fourth quarter of 2015 to $49.18 per barrel in the same period of 2016.

Despite the fourth quarter increase, crude oil prices were under pressure throughout 2016 due to a continued global production increase that outpaced demand growth, leading to a large observed rise in global inventory. The average Brent crude oil price decreased 17 percent, from $52.46 per barrel in 2015 to $43.69 per barrel in 2016.

Henry Hub natural gas prices averaged $2.98 per million British thermal units (MMBTU) in the fourth quarter of 2016, an increase of 31 percent compared with $2.27 per MMBTU in the fourth quarter of 2015. Natural gas prices increased in the fourth quarter due to growth in demand, coupled with declining production.

On average, Henry Hub natural gas prices decreased 8 percent from $2.67 per MMBTU in 2015 to $2.46 per MMBTU in 2016, mainly due to strong production levels and a warmer-than expected winter reducing demand below expectations. In 2016, U.S. underground gas storage inventories reached their highest levels in five years.

Our realized natural gas liquids prices averaged $21.82 per barrel in the fourth quarter of 2016, an increase of 33 percent compared with $16.42 per barrel in the same quarter of 2015.

Similar to natural gas and crude oil, our natural gas liquids prices also declined on average in 2016. Our average realized natural gas liquids prices decreased 6 percent, from $17.79 per barrel in 2015 to $16.68 per barrel in 2016, as the expansion in tight oil production boosted supplies of natural gas liquids, resulting in continued downward pressure on natural gas liquids prices in the United States.

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Declining global crude oil prices resulted in the Western Canada Select benchmark price experiencing a 17 percent decline, from $35.21 per barrel in 2015 to $29.36 per barrel in 2016. Consequently, our realized bitumen price experienced a decrease relative to 2015 price levels. Our realized bitumen price was $15.27 per barrel in 2016, a decrease of 18 percent compared with $18.72 per barrel in the same period of 2015.

Our worldwide annual average realized price was $28.35 per barrel of oil equivalent (BOE) in 2016, a decrease of 17 percent compared with $34.34 per BOE in 2015. 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.

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Outlook

Full-year 2017 production is expected to be 1,540 to 1,570 MBOED. This results in flat to 2 percent growth compared with full-year 2016 production of 1,540 MBOED when adjusted for 2016 dispositions of 27 MBOED. First-quarter 2017 production is expected to be 1,540 to 1,580 MBOED. Production guidance for 2017 excludes Libya and the impact of future dispositions.

Marketing Activities

In line with our strategic objectives, we are currently marketing certain non-core assets primarily associated with North American natural gas. We expect to generate $5 billion to $8 billion in proceeds over the next two years from asset sales.

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:

2016 vs. 2015

Losses for ConocoPhillips decreased 19 percent in 2016. The decrease was mainly due to:

The decrease in losses was partly offset by:

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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.

Income Statement Analysis

2016 vs. 2015

Sales and other operating revenues decreased 20 percent in 2016, mainly as a result of lower prices across all commodities. Additionally, sales and other operating revenues decreased due to lower natural gas, crude oil and natural gas liquids sales volumes, mainly from dispositions and field decline, partly offset by increased bitumen sales volumes.

Equity in earnings of affiliates decreased 92 percent in 2016. The decrease was primarily due to lower commodity prices, increased DD&A mainly from Trains 1 and 2 being placed in service at APLNG, and a 2016 deferred tax charge of $174 million resulting from a tax functional currency change. The decrease in earnings was partly offset by higher sales volumes at APLNG and FCCL Partnership, as well as lower production taxes at Qatar Liquefied Gas Company Limited (3) (QG3).

Gain on dispositions decreased 39 percent in 2016. The decrease resulted from the absence of a $583 million before-tax gain in 2015 from the sales of producing properties in East Texas and North Louisiana, South Texas, and a certain pipeline and gathering assets in South Texas, as well as a $26 million before-tax loss on the sale of our interest in the Block B PSC in Indonesia in 2016. The decrease was partly offset by the absence of a $149 million before-tax loss on the disposition of non-core assets in western Canada in the fourth quarter of 2015; and gains on the 2016 dispositions of ConocoPhillips Senegal B.V., the entity that held our interests in three exploration blocks offshore Senegal, the Alaska Beluga River Unit natural gas field, and non-core assets in the Lower 48. For additional information on gains on dispositions, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

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Other income increased 104 percent in 2016, mainly due to a gain of $88 million from our receipt of mineral properties and active leases from the Greater Northern Iron Ore Properties Trust in the fourth quarter of 2016. Other income was further increased $76 million before-tax for a damage claim settlement in our Lower 48 segment.

Purchased commodities decreased 20 percent in 2016, mainly due to lower natural gas prices.

Production and operating expenses decreased 19 percent in 2016, mainly due to lower operating expense activity, reduced headcount and dispositions of non-core assets, as well as favorable foreign currency impacts.

Selling, general and administrative (SG&A) expenses decreased 24 percent in 2016, primarily due to reduced restructuring expenses, lower headcount and reduced activity. The decrease was partly offset by increases from market impacts on certain compensation programs.

Exploration expenses decreased 54 percent in 2016, primarily as a result of lower leasehold impairment expense, dry hole costs, and other exploration expenses.

Leasehold impairment expense was reduced, mainly due to the absence of 2015 before-tax charges of $575 million for our Chukchi Sea leasehold and capitalized interest; $493 million for Angola Blocks 36 and 37; and $447 million for certain Gulf of Mexico leases, partly offset by 2016 impairments of our Melmar, Gibson, Tiber and other Gulf of Mexico leaseholds.

Dry hole costs were reduced due to the absence of before-tax charges of $1,141 million in 2015, mainly from wells in deepwater Gulf of Mexico, Horn River and Northwest Territories in Canada, Angola Blocks 36 and 37, and Malaysia. The reduction in costs was partly offset by before-tax charges in 2016, including $434 million from several wells in deepwater Gulf of Mexico and $256 million for two wells in Nova Scotia.

Other exploration expenses were reduced mainly due to the absence of a $335 million before-tax charge in 2015 related to the termination of our Ensco Gulf of Mexico deepwater drillship contract, partly offset by before-tax rig cancellation charges and third-party costs of $146 million for our final Gulf of Mexico deepwater drillship contract in 2016.

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.

Impairments decreased 94 percent in 2016. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 18 percent in 2016, primarily as a result of lower production taxes, mainly in our Alaska and Lower 48 segments, given reduced commodity prices and the absence of the impact of a transportation cost ruling by the Federal Energy Regulatory Commission in the fourth quarter of 2015 in Alaska. Taxes other than income taxes were additionally decreased due to lower property taxes in 2016 in our Alaska and Lower 48 segments.

Interest and debt expense increased 35 percent in 2016, primarily due to lower capitalized interest on projects and increased debt.

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

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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 and 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.

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.

SG&A expenses increased 30 percent in 2015, primarily due to $407 million in restructuring and pension settlement expenses, 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 before-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.

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, 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 income tax provision (benefit) and effective tax rate.

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Summary Operating Statistics

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, 2016, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.

Total production, including Libya, of 1,569 MBOED decreased 1 percent in 2016 compared with 2015. The decrease in total average production primarily resulted from normal field decline and the loss of 72 MBOED mainly attributable to the 2015 dispositions of several non-core assets in the Lower 48, western Canada and the sale of our interest in the Polar Lights Company in Russia. The decrease in production was partly offset by additional production from major developments, including tight oil plays in the Lower 48; APLNG in Australia; the Western North Slope in Alaska; the Kebabangan gas field in Malaysia; and the Greater Ekofisk Area in Norway. Improved drilling and well performance in Canada, Norway, the Lower 48, and China, as well as lower unplanned downtime in the Lower 48 also partly offset the decrease in production. Adjusted for downtime and dispositions of 66 MBOED, our production, excluding Libya, increased by 44 MBOED, or 3 percent, compared with 2015. Assets sold in 2016 produced 27 MBOED and 36 MBOED in 2016 and 2015, respectively.

In 2015, average production from continuing operations, including Libya, increased 3 percent compared with 2014, while average liquids production increased 4 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. Adjusted for downtime and dispositions of 13 MBOED,

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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.

Alaska

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. In 2016, Alaska contributed 19 percent of our worldwide liquids production and less than 1 percent of our natural gas production.

2016 vs. 2015

Alaska reported earnings of $319 million in 2016, compared with earnings of $4 million in 2015. The increase in earnings was mainly due to:

The increase in earnings was partly offset by lower crude oil prices and higher DD&A expense, mainly due to capital additions.

Average production increased 1 percent in 2016 compared with 2015, primarily due to new production from the Alpine CD5 drill site and strong well performance in the Greater Prudhoe Area. The production increase was partly offset by normal field decline.

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.

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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.

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 2016, the Lower 48 contributed 30 percent of our worldwide liquids production and 32 percent of our natural gas production.

2016 vs. 2015

Lower 48 reported a loss of $2,257 million after-tax in 2016, compared with a loss of $1,932 million after-tax in 2015. The increase in losses was primarily due to:

The increase in losses was partly offset by:

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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 2016 average realized crude oil price of $37.49 per barrel was 13 percent less than WTI of $43.20 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 decreased 11 percent in 2016 compared with 2015. The decrease was mainly attributable to normal field decline and the 2015 disposition of non-core properties in East Texas and North Louisiana, as well as South Texas. The reduction was partly offset by new production and well performance, primarily from Eagle Ford, Bakken and the Permian Basin, as well as lower unplanned downtime.

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 on the disposition of certain properties in South Texas, East Texas and North 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.

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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Canada