20162017

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form10-K

(Mark One)

For the fiscal year ended        December 31, 20162017                                             

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 RegulationS-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 RegulationS-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 Form10-K or any amendment to this Form10-K. [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” andfiler,” “smaller reporting company” and “emerging growth company” in Rule12b-2 of the Exchange Act.

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

Emerging growth company [  ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [  ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Act). [  ]  Yes    [x]  No

The aggregate market value of common stock held bynon-affiliates of the registrant on June 30, 2016,2017, 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,$43.96, was $54.0 billion.

The registrant had 1,235,832,4691,174,577,506 shares of common stock outstanding at January 31, 2017.2018.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 16, 201715, 2018 (Part III)

TABLE OF CONTENTS

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 72.70.

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 approvedcompleted the separation of ourthe 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. Ourdiverse 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, 2016,2017, ConocoPhillips employed approximately 13,30011,400 people worldwide.

We operate in a commodity-price driven industry, subject to volatility. In line with this view, we set our operating plan for 2017, defining our cash allocation priorities which would be reinforced and partly funded by sales of noncore assets during the year. In November 2016, we announced our plannedplan to generate $5 billion to $8 billionbillon of proceeds over two years by optimizing our portfolio to focus on value-preserving, lowcost-of-supply projects that strategically fit our development plans. In 2017, our total consideration from asset disposition program, primarily associated with North American naturaldispositions was approximately $16 billion. We disposed of assets including our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) Partnership, as well as the majority of our western Canada gas assets, overand our interest in the next two years.San Juan Basin gas asset. Proceeds from dispositions were directed towards our cash allocation priorities and for general corporate purposes. For additional information on our cash allocation priorities and our asset sales, see the “Outlook”Business Environment and Executive Overview section ofwithin Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 6—4—Assets Held for Sale, Sold or Sold,Acquired, in the Notes to Consolidated Financial Statements,. respectively.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 24—23—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2016,2017, 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:

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 8177 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 1,5691,377 thousand barrels of oil equivalent per day (MBOED) decreased 112 percent in 20162017 compared with 2015.2016. The decrease in total average production primarily resulted from normal field declinenoncore asset dispositions, including our Canada and the loss of 72 MBOED mainly attributable to the 2015 dispositions of several non-core assetsSan Juan transactions in the Lower 48, western Canada2017 and the sale of our interest in the Polar Lights CompanyBlock B production sharing contract (PSC) in Russia.Indonesia in 2016, and normal field decline. 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;Malikai and the Kebabangan gas field in Malaysia; Surmont in Canada; and the Greater Ekofisk AreaAPLNG in Norway.Australia. Improved drilling and well performance in Canada,Alaska, Norway the Lower 48, and China as well as lower unplanned downtime in the Lower 48 also partly offset the decrease in production. Assets soldExcluding Libya, our 2017 production was 1,356 MBOED. Adjusted for the impact of closed and planned dispositions of 191 MBOED in 2016 produced 27 MBOED2017 and 36434 MBOED in 2016 and 2015, respectively.Libya, underlying production increased 32 MBOED, or 3 percent, compared with 2016.

Our worldwide annual average realized price was $39.19 per BOE in 2017, an increase of 38 percent compared with $28.35 per BOE in 2016, a decrease of 17 percent compared with $34.34 per BOE in 2015, which reflected lowerreflecting higher average realized prices across all commodities. Our worldwide annual average crude oil price decreased 15increased 27 percent in 2016,2017, from $48.26 per barrel in 2015 to $40.86 per barrel in 2016.2016 to $51.96 per barrel in 2017. Additionally, our worldwide annual average natural gas liquids prices decreased 6increased 51 percent, from $17.79 per barrel in 2015 to $16.68 per barrel in 2016.2016 to $25.22 per barrel in 2017. Our worldwide annual average natural gas price decreased 24increased 36 percent, from $3.96 per MCF in 2015 to $3.00 per MCF in 2016.2016 to $4.07 per MCF in 2017. Average annual bitumen prices also decreased 18increased 48 percent, from $18.72 per barrel in 2015 to $15.27 per barrel in 2016.2016 to $22.66 per barrel in 2017.

ALASKA

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids,and natural gas and LNG.liquids. 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 0.51 million net undeveloped acres atyear-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, 2017. Alaska operations contributed 1922 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 anticipatedwas achieved in 2018.the fourth quarter of 2017.

Western North Slope

On the Western North Slope, we operate the Colville River Unit, which includes the Alpine Field and three satellite fields: Nanuq, Fiord and Qannik. Alpine is located 34 miles west of Kuparuk. In October 2015, first oil was achieved at Alpine West CD5, a new drill site which extends the Alpine reservoir west into the National Petroleum Reserve-Alaska(NPR-A). During the year, we approvedcontinued drilling an additional 18 wells bringing CD5 up to its full permit capacity.using the available well slots on the pad.

The Greater Mooses Tooth Unit, the first unit established entirely within theNPR-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 2020,2021, respectively.

Cook Inlet Area

We have a 100 percentIn January 2018, we sold our interest and are the operator ofin the Kenai LNG Facility in the Cook Inlet Area. The Kenai LNG Facility includesfacility, which consisted of a 1.6million-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 wastankers, had no LNG export program in 20162017 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 aIn the first quarter of 2017, we recorded an asset impairment and assigned our 4.9 percent interest in the Point Thomson Unit, which isunit, located approximately 60 miles east of Prudhoe Bay. An Initial Production System (IPS) was brought online in April 2016, and achieved full productionBay, to the other owners of 400 BOED net of condensate in December.the field.

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 “AKLNGco-venturers”), completed preliminaryfront-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 intentionAGDC is continuing to continue efforts to advance a North Slope Gasprogress the project the AKLNG co-venturers executed certain agreements to enhance AGDC’s ability to do so.and has recently signed several Memorandums of Understanding with various potential LNG buyers in Asia. We remain supportive of AGDC’s efforts to progress a project.advance the project and intend to make our equity gas available for sale to the project at mutually agreed, commercially reasonable terms.

Exploration

In 2016, we drilled three exploration wells in the NPR-A. TwoAppraisal of these wells, Tinmiaq 2 and 6, form the Willow discovery, which isDiscovery, located in the northeast portion of the NPR-A. The thirdNational Petroleum Reserve-Alaska, continued throughout 2017 with the acquisition of3-D seismic which is currently being processed. In 2018, we will continue appraisal of the discovery with drilling of additional wells. Further exploration well was recorded to dry hole expenseof other state and federal leases is planned in 2018.

We were successful in state and federal lease sales in the North Slope 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 13913 tracts for a total of 737,252 grossapproximately 78,000 net acres.

Acquisition

In January 2018, we entered into an agreement to acquire certain oil and gas assets in Alaska. The acquisition is subject to regulatory approval. We will have a 100 percent interest in approximately 1.2 million acres of exploration and development lands, including the Willow Discovery. For additional information, see Note 4—Assets Held for Sale, Sold or Acquired, in the Notes to Consolidated Financial Statements.

Transportation

We transport the petroleum liquids produced on the North Slope to south central Alaska through an800-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-ownedwholly 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.

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, lowcost-of-supply plays. In July 2015, we announcedWe disposed of several noncore assets within the Lower 48 in 2017, including our plan to reduce future deepwater exploration spending. We have subsequently terminated our Gulf of Mexico deepwater drillship contracts.interests in the San Juan Basin and the Panhandle. We hold 12.410.4 million net onshore and offshore acres in the Lower 48. In 2016,2017, the Lower 48 contributed 30 percent of our worldwide liquids production and 3227 percent of our natural gas production.

Onshore

We hold 12.310.4 million net acres of onshore conventional and unconventional acreage in the Lower 48, the majority of which is either held by production or owned by the company. Our unconventional holdings total approximately 2.61.8 million net acres in the following areas:

The majority of our 20162017 onshore production originated from the Eagle Ford,Ford; San Juan, Permianwhich we disposed of during the year; Bakken; and Bakken.Permian. Onshore activities in 20162017 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 20162017 drilling activity levels declinedincreased relative to 20152016 due to reducedhigher capital spending in the low commodity price environment.spending. Our major focus areas in 20162017 included the following:

In 2015, weWe completed the sale of certain non-coreour interests in the San Juan Basin on July 31, 2017, and Panhandle assets in East Texas and North Louisiana and South Texas.on September 29, 2017. Production from the assets sold was 3374 MBOED, approximately 619 percent of the total Lower 48 segment production in 2015. In the second quarter of 2016, we completed the sale of certain non-core assets2017. For additional information on our asset dispositions, see Note 4—Assets Held for Sale, Sold or Acquired, in the Delaware basin. The full-year 2016 production from the assets sold was 1 MBOED.Notes to Consolidated Financial Statements.

Gulf of Mexico

Atyear-end 2016, 2017, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one operated field and three fields operated byco-venturers, totaling approximately 68,000 net acres, including:

Exploration

At December 31, 2016,2017, we held approximately 73,0005,000 net acres in the deepwater Gulf of Mexico.

We own aOur 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.2009. In Februaryearly 2017, the sixth Shenandoah well, ShenandoahWR52-3, reached total depth. Drillingdepth and was followed by the drilling of a sidetrack well from Shenandoah WR52-3 also commenced in February.

As partWR52-3. Following the suspension of our continued phased exit from deepwater exploration, in 2016, we decided not to pursue further development ofappraisal activity by the nonoperated Gibson and Tiber wells, collectively known asoperator during the Tigris project. Accordingly,year, 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.entire development. On December 19, 2017, we elected to withdraw from the Shenandoah leases. The withdrawal was effective February 17, 2018.

In 2016, we drilled a total of five operated unconventional wells, primarily in the Eagle Ford. Our onshore focus areas include the Niobrara in the Denver-Julesburg Basin and 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 2013,2016 and 2017, we agreed with Freeport LNG Development, L.P. to terminate our long-term agreement to use 0.9 billion cubic feet per daydrilled a total 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,five operated unconventional wells in the Notes to Consolidated Financial Statements.Powder River Basin, four of which were expensed as dry holes in November 2017. The fifth Powder River Basin well was expensed as a dry hole in January 2018.

Facilities

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$247 million at December 31, 2016.2017. 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

CANADA

Our Canadian operations mainly consist of natural gas fields in western Canada andan oil sands developmentsdevelopment in the Athabasca Region of northeastern Alberta.Alberta and a liquids-rich unconventional play in western Canada. In 2016,2017, operations in Canada contributed 2316 percent of our worldwide liquids production and 146 percent of our natural gas production.

Western Canada

										2017
			Interest				Operator				Liquids MBD				Natural Gas MMCFD				Bitumen MBD				Total      MBOED
Average Daily Net Production
Western Canada			Various	%			Various				12				187				-				43
Surmont			50.0				ConocoPhillips				-				-				59				59
Foster Creek			50.0				Cenovus				-				-				26				26
Christina Lake			50.0				Cenovus				-				-				37				37
Total Canada											12				187				122				165

Our operations

On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada extend across Alberta and British Columbia. We operategas assets to Cenovus Energy. Production from the assets sold was 103 MBOED, approximately 62 percent of the total Canada segment production in 2017. For additional information on our asset dispositions, see Note 4—Assets Held for Sale, Sold or have ownership interests in approximately 30 natural gas processing plantsAcquired, 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:Notes to Consolidated Financial Statements.

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 0.90.6 million net acres of land in the Athabasca Region of northeastern Alberta.

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 fourthree 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 coveringWe hold approximately five0.1 million grossnet acres in the deepwater Shelburne Basin, offshore Nova Scotia. In 2016, we recorded dry hole expenses associated withemerging Montney play in northeast British Columbia and 0.2 million net acres in Canol Northwest Territories. Our Montney activity in 2017 included completing two and bringing onstream six appraisal wells and acquiring approximately 27,000 additional net acres. Late appraisal drilling activity will continue in 2018 to further explore 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.area’s resource potential.

We hold approximately 0.7 million net acresSurrender of Interest documents for our 30 percent nonoperated working interest in six exploration licenses in the emerging Montney, Muskwa, DuvernayShelburne Basin, offshore Nova Scotia, were submitted on December 15, 2017, to initiate the exit process, following previously announced results of thetwo-well exploration drilling campaign at Cheshire 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.Monterey Jack.

EUROPE AND NORTH AFRICA

The Europe and North Africa segment consists of operations and exploration activities in Norway, the United Kingdom and Libya. In 2016,2017, operations in Europe and North Africa contributed 1418 percent of our worldwide liquids production and 1215 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. The Ekofisk and Eldfisk fields consist of several production platforms and facilities, including the Ekofisk South and Eldfisk II developments which achieved first production in 2013 while Eldfisk II achieved startup in January 2015.and 2015, respectively. Continued development drilling in the Greater Ekofisk Area will contribute additional production over the coming years, as additional wells come online.

The Alvheim developmentField is located in the northern part of the North Sea near the border with the U.K. sector, 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 exportedtransported to the ContinentEurope via gas processing terminals in Norway, while the remainder is exportedtransported 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.development in the Norwegian Sea. The operator is targetingplanning for first gas for Aasta Hansteen by late 2018.

Exploration

WeIn 2017, we participated in two nonoperated exploration wellsthe Korpfjell Well in the OsebergBarents Sea and Alvheim areas. Both wells were discoveriesthe Carmen Well in the Heidrun Area of Norway, both of which made gas discoveries. The Carmen Well was considered a discovery and areis currently undergoing evaluation. Weunder evaluation, while the Korpfjell Well is not considered commercial. In 2017, we were awarded threefour new exploration licenses in 2016, including the PL845PL865, PL888, PL890 and PL782SB, both with interests of 40 percent,PL891; and PL859, which has a 15 percent interest.two acreage additions PL053C and PL782SC. Additionally, two new licenses, PL775 and PL626, were captured throughfarm-in.

Transportation

We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a220-mile pipeline which carries crude oil from Ekofisk to a crude oil stabilization and natural gas liquids processing facility in Teesside, England.

United Kingdom

* Includes the Chevron-operated Alder Field, ConocoPhillips equity 26.3%.

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 partythird-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.Platform.

TheJ-Area consists of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. The Jasmine FieldJ-Area gas is a high-pressure, high-temperature gas condensate reservoir located approximately six miles west ofprocessed on the Judy Platform. ThePlatform and transported through the Central Area Transmission System Pipeline, while liquids are transported to Teesside through the Norpipe system. AJ-Area 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-linkeddrilling campaign commenced in 2017, which is expected to provide additional volumes in the existing Judy Platform.coming years as wells are brought online.

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.ongoing. 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 a36-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 forexpected in 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.

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 inmid-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 three2016. In 2017, we had 17 crude liftings from Es Sider in January 2017.Sider. We expect a gradual, continuedramp-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 2016,2017, operations in the Asia Pacific and Middle East segment contributed 14 percent of our worldwide liquids production and 4252 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 CBMcoalbed methane (CBM) from the Bowen and Surat basins in Queensland, Australia, to supply the domestic gas market and convertingconvert the coalbed methaneCBM into LNG. Natural gas is sold to domestic customers, while LNG is exported.for export. Origin operates APLNG’s upstream production and pipeline system, and we operate the downstream LNG facility, located on Curtis Island near Gladstone, Queensland, as well as the LNG export sales business.

Two fully subscribed 4.5 million tonnes-per-year4.5-million-metric-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 agreementagreements for an additional 3.37.6 million metric tonnes of LNG per year, through 2035, and Japan-based Kansai Electric Power Co., Inc. under a20-year sales agreement for approximately 1 million metric tonnes of LNG per year.

APLNG has an $8.5 billion project finance facility, which was fully drawn down and had an outstanding balance of which $8.5$7.9 billion had been drawn from the facility at December 31, 2016.2017. In connection with the execution of the project financing, we provided a completion guarantee for ourpro-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. In August 2017, we reached financial completion for Train 2, which removed the remaining guarantee. For additional information, see Note 4—2—Variable Interest Entities (VIEs), Note 7—5—Investments, Loans and Long-Term Receivables, and Note 12—11—Guarantees, in the Notes to Consolidated Financial Statements.

Bayu-Undan

The Bayu-Undan gas condensate field is located in the Timor Sea Joint Petroleum Development Area between Timor-Leste and Australia. We also operate and own a 56.9 percent interest in the associated Darwin LNG Facility, located at Wickham Point, Darwin.

The Bayu-Undan natural gas recycle facility processes wet gas; separates, stores and offloads condensate, propane and butane; andre-injects dry gas back into the reservoir. In addition, a310-mile natural gas pipeline connects the facility to the 3.5 million tonnes-per-year3.5-million-metric-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 2016,2017, we sold 168150 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 evaluatedhas been sanctioned with the front-end engineeringinternal, joint venture and design phase approaching completion.regulatory approval in March 2017. The currentproject premise is that drillingconsists of one subsea and two platform wells, willwith drilling to commence in 2018, pending internal, joint venture and regulatory approval.

ConocoPhillips served a NoticeApril 2018. Production is expected to commence in the third quarter 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 2016.2018.

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 withWA-1-L, an adjoining license area. Natural gas is produced from these licenses.licenses, which are due to expire in 2019.

Greater Sunrise

We have a 30 percent interest in the Greater Sunrise natural gas and condensate field located in the Timor Sea. In April 2016, the Timor-Leste Government initiatedand Australia through engagement in a conciliation process under the United Nations Convention ofon the Law of the Sea (UNCLOS)have reached agreement on the central elements of a maritime boundary delimitation between them in an attemptthe Timor Sea. The Governments’ agreement, to negotiate permanent maritime boundaries. The conciliation ison-goingbe formalized in a new treaty, constitutes a package that addresses boundaries, the legal status of the Greater Sunrise gas field, the establishment of a Special Regime for Greater Sunrise, a pathway to development of the resource and the sharing of resulting revenue. Discussions are ongoing between the governments of Timor-Leste and Australia.

The UNCLOS conciliation does not directly impact our underlying interests in Sunrise; however, wetwo Governments and the Sunriseco-venturers are unable to commit to further commercial and technical work activities due with respect to the uncertainty created bydevelopment concept for Greater Sunrise. Until the lack of government alignment. Accordingly, currentGovernments and the Sunriseco-venturers are aligned on a development concept, activities are currently restricted to compliance and social investment, as well as maintaining relationships and continued engagement with the Governments for a future development options for Sunrise.option.

Exploration

We operate three exploration permits in the Browse Basin, offshore northwest Australia, in which we own a 40 percent interest in permitsWA-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 andKronos-1. Phase II of the drilling campaign resulted in five additional discoveries:Boreas-1,Zephyros-1,Proteus-1 SD2,Poseidon-North-1 andPharos-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 Octoberfields in 2016. DrillingThe drilling of the nextBarossa-5 andBarossa-6 appraisal well, Barossa-5, commencedwells was completed in January 2017. Drilling of a subsequent well, Barossa-6, may follow dependent on2017 with good quality,gas-bearing reservoir intersected at both. Additionally, the results of Barossa-5.retention lease over the Barossa Discovery was renewed during the year.

Indonesia

We operate three production sharing contracts (PSCs)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. During 2017, we acquired2-D seismic data in the area.

Transportation

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

China

The Penglai 19-3, 19-919-3,19-9 and25-6 fields are located in Bohai Bay Block 11/05. Production from the Phase 1 development of the Penglai19-3 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 Penglai19-9 Field, a new wellhead platform, which adds up to 62 wells, is progressing according to schedule, with two19 wells completed and brought online inthrough December 2016.2017.

We sanctioned the Penglai19-3/19-9 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, Panyu5-1 and Panyu11-6. The production period for Panyu4-2 and5-1 will expire in 2018, and the production period for Panyu11-6 will expire in 2022.

Exploration

In 2016,2017, we participated in a successful appraisal well in the Penglai fields,Field, which will support future development plans. In late 2017, we began a full-field3-D seismic program at Penglai, covering Phase 3 and other future development opportunities. The program is expected to continue in 2018.

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, deepwaterDeepwater Block 3E, Block SK313 and BlockWL4-00 are located off the eastern Malaysian state of Sarawak.

Block G

We have a 21 percent interest in the unitized Siakap North-Petai oil field, which began producing in the first quarter of 2014 and reached its estimated net annual peak production of 5 MBOED in 2015.2014.

First production from the Malikai oil field was achieved in December 2016, with estimated net annual peak production of 1821 MBOED expected in 2019.2018. We own a 35 percent interest in Malikai. 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 interestThe well was expensed in the Malikai, Limbayong and Pisagan discoveries.2017.

Block J

First production forfrom the Gumusut Field 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 reached2014. Our ownership in 2016. Unitization of the Gumusut Field is currently at 29 percent following the finalization of the unitization 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 agreeda redetermination of the Block J and Block K Malaysia Unit, both 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 deepwaterDeepwater Block 3E, which encompasses approximately 480,000 gross acres offshore Sarawak. Seismic processing was completed in 2015. TheLangsat-1 exploration well was spuddrilled and expensed as a dry hole in February 2017.

In the fourth quarter of 2016, we entered into afarm-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 theSadok-1 exploration well in January 2017, we assumed operatorship of the block from PETRONAS.

We were awarded BlockWL4-00, which encompasses approximately 629,000 gross acres, in January 2017. We have a 50 percent operated interest in this block which includes theSalam-1 oil discovery. A new

We completed a3-D seismic survey in Block SK 313 and BlockWL4-00 in 2017. Further exploration drilling is planned for 2017 with drilling of an appraisal well expected to occur in 2018.

Brunei

Exploration

We have a 6.25 percent working interest in the deepwater BlockCA-2 PSC, which has an exploration period through December 2018. PSC. Exploration has been ongoing since September 2011, with natural gas discovered at the KelidangNE-1 andKeratau-1 wells in 2013 and at the KeratauSW-1 well 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.

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 year25-year life, in addition to a 7.8 million grosstonnes-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 BlockVMM-3. The block extends over approximately 67,000 net acres and contains thePicoplata-1 well, which completed drilling in 2015. Production tests2015 and appraisaltesting in 2017. Socialization and environmental permitting activities are expected to continue throughout 2018.

In July 2017, ConocoPhillips Colombia Ventures Ltd. and Canacol Energy Colombia S.A. executed an Additional Contract for the exploration and exploitation of unconventional reservoirs in an area identified as theVMM-2 Block. As a result, ConocoPhillips Colombia Ventures Ltd. and Canacol Energy Colombia S.A. also executed a joint operating agreement. We have an 80 percent operated working interest in the area are ongoing.block which extends over approximately 58,000 net acres and is contiguous to theVMM-3 Block.    

We holdIn 2017, we relinquished our 70 percent nonoperated interests in the deep rights in the Santa Isabel Block inand terminated 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.

The exploration and production contract for the VMM27 Block, both 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.Basin.

Chile

Exploration

In June 2016, we entered into an agreement with Empresa Nacional Del Petroleo (ENAP) to acquire an additional 44We have a 49 percent participating interest in the onshore Coiron Block located in the Magallanes Basin in southern Chile where we already had 5 percent participation. AssignmentChile. In December 2017, two wells drilled in 2016, were expensed as dry holes.

Venezuela and Ecuador

For discussion of the additional participating interest to ConocoPhillips was approved by the Chilean Ministry of Energyour contingencies in Venezuela 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,Ecuador, see Note 13—12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Ecuador

In December 2012, an ICSID Tribunal issued a decision on liability in favor of Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. In February 2017, the tribunal unanimously awarded Burlington $380 million for Ecuador’s unlawful expropriation and breach of theU.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.

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 (MWCC)

We are a founding member of the Marine Well Containment Company (MWCC),MWCC, anon-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—2—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

Subsea Well Response Project (SWRP)

In 2011, we, along with several leading oil and gas companies, launched the Subsea Well Response Project (SWRP),SWRP, anon-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, anon-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 arenot-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.

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, 2016.2017. No difference exists between our estimated total proved reserves foryear-end 2016 andyear-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 2016.2017.

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 Commercialcommercial 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 2.01.7 trillion cubic feet of natural gas, including approximately 363303 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 18099 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2027.2029. 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, 2016,4, 2017, issue of theOil and Gas Journal, we were the third-largest U.S.-based oil and gas company in worldwide liquids production and reserves, and the fourth-largest U.S.-based oil and gas company in worldwide natural gas production and reserves in 2015.2016. 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 2016,2017, we held a total of 714734 active patents in 4947 countries worldwide, including 286328 active U.S. patents. During 2016,2017, we received 3732 patents in the United States and 6640 foreign patents. Our products and processes generated licensing revenues of $128$79 million in 2016.2017. 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 $100 million, $116 million and $222 million in 2017, 2016 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.

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 6361 through 6664 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 20162017 and those expected for 20172018 and 2018.2019.

Website Access to SEC Reports

Our internet website address iswww.conocophillips.com. Information contained on our internet website is not part of this report on Form10-K.

Our Annual Reports onForm 10-K, Quarterly Reports onForm 10-Q, Current Reports onForm 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 atwww.sec.gov.

Item 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form10-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 20162017 for Brent crude oil, WTI crude oil, Henry Hub natural gas and our realized natural gas liquids all decreased by more than 5at least 30 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,2014 despite having improved by at least 18 percent when compared with the same period of 2015.2016. 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 twothree years, we recognized several impairments, which are described in Note 9—8—Impairments and the “APLNG” section of Note 7—5—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 and repurchase shares 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.

Additionally, our share repurchase program does not obligate us to acquire any specific number of shares. Any downward revision in our distribution or share repurchase program could have a material adverse effect on the market price of our common stock.

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. In addition, although we anticipate we will be able to repay our existing indebtedness when it matures or in accordance with our stated plans, there can be no assurance we will be able to do so. Our ability to obtain additional financing, or refinance our existing indebtedness when it matures or in accordance with our stated plans, 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. DueFor example, due to the significant decline in prices for crude oil, bitumen, natural gas, natural gas liquids and LNG in 2015, 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.industry in 2016. 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 declinesvolatility 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.

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.

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, including changes resulting from the implementation and interpretation of the Tax Cuts and Jobs Act, 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 violatenon-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 2016,2017, and 5545 percent of our proved reserves, as of December 31, 2016,2017, was located outside the United States. We are subject to risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas, bitumen, natural gas liquids or LNG pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations. In particular, some countries where we operate lack well-developed legal systems or have not adopted clear legal and regulatory frameworks for oil and gas exploration and production. This lack of legal certainty exposes our operations to increased risks, including increased difficulty in enforcing our agreements in those jurisdictions and increased risks of adverse actions by local government authorities, such as expropriations.

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

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

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

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

We 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.

As part of our disposition strategy, on May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy. Consideration for the transaction included 208 million Cenovus Energy common shares. We may not be able to liquidate the shares issued to us by Cenovus Energy at prices we deem acceptable, or at all.

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.

Item 3.

LEGAL PROCEEDINGS

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 2016,2017, as well as matters previously reported in our 20152016 Form10-K and ourfirst-, second- and third-quarter 20162017 Form10-Qs that were not resolved prior to the fourth quarter of 2016.2017. 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 66penalties exceeding $100,000.

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.Refinery. The settlement involves certain capital projects and payment of $125,000. TheAfter the settlement has beenwas filed with the Court for final approval, and the Sierra Club has sought and was granted approval to intervene in the casecase. The settlement and a first modification have been entered by the Court, but the Sierra Club still seeks to opposereopen and challenge the settlement. A court hearing is scheduled for March 2017.

Not applicable.

EXECUTIVE OFFICERS OF THE REGISTRANT

*On February 15, 2017.2018.

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, 2017.15, 2018. Set forth below is information about the executive officers.

Janet L. Carrigwas appointed Senior Vice President, Legal, General Counsel and Corporate Secretary in 2007. On February 14, 2018, Ms. Carrig announced her decision to retire as Senior Vice President, Legal, General Counsel and Corporate Secretary. Ms. Carrig plans to remain in her current position until her successor is appointed.

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

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

Glenda M. Schwarzwas 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.

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.”