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2012

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One) 

[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) 

 OF THE SECURITIES EXCHANGE ACT OF 1934 

 For the fiscal year ended December 31, 2012 

 OR 

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) 

 OF THE SECURITIES EXCHANGE ACT OF 1934 

 For the transition period from to 

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware 01-0562944

(State or other jurisdiction of (I.R.S. Employer

incorporation or organization) Identification No.)

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:

Title of each class

Name of each exchange

 on which registered 

Common Stock, $.01 Par Value New York Stock Exchange

6.65% Debentures due July 15, 2018 New York Stock Exchange

7% Debentures due 2029 New York Stock Exchange

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

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

[x] Yes [ ] No

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

[ ] Yes [x] No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during

the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements

for the past 90 days. [x] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to

be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to

submit and post such files).

[x] Yes [ ] No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best

of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this

Form 10-K. [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the

definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2012, the last business day of the registrant’s most recently

completed second fiscal quarter, based on the closing price on that date of $55.88, was $67.9 billion. The registrant, solely for the purpose of this required

presentation, had deemed its Board of Directors to be an affiliate and deducted their stockholdings of 66,914 shares in determining the aggregate market

value.

The registrant had 1,220,992,874 shares of common stock outstanding at January 31, 2013.

Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 14, 2013 (Part III)
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TABLE OF CONTENTS

Item Page

 PART I 

1 and 2. Business and Properties 1 

 

 Corporate Structure 1 

 

 Segment and Geographic Information 1 

 

 Alaska 4 

 

 Lower 48 and Latin America 6 

 

 Canada 9 

 

 Europe 11 

 

 Asia Pacific and Middle East 13 

 

 Other International 18 

 

 LUKOIL Investment 20 

 

 Competition 22 

 

 General 22 

1A. Risk Factors 23 

1B. Unresolved Staff Comments 26 

3.

 Legal Proceedings 26 

4.

 Mine Safety Disclosures 27 

 Executive Officers of the Registrant 28 

 PART II 

5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and

Issuer Purchases of Equity Securities 30 

6. Selected Financial Data 31 

7.

 

Management’s Discussion and Analysis of Financial Condition and

Results of Operations 32 

7A. Quantitative and Qualitative Disclosures About Market Risk 68 

8. Financial Statements and Supplementary Data 71 

9.

 

Changes in and Disagreements with Accountants on Accounting and

Financial Disclosure 172 

9A. Controls and Procedures 172 

9B. Other Information 172 

 PART III 

10. Directors, Executive Officers and Corporate Governance 173 

11. Executive Compensation 173 

12.

 

Security Ownership of Certain Beneficial Owners and Management and

Related Stockholder Matters 173 

13. Certain Relationships and Related Transactions, and Director Independence 173 

14. Principal Accounting Fees and Services 173 

 PART IV 

15. Exhibits, Financial Statement Schedules 174 

 Signatures 181 
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 67.

Items 1 and 2. BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural

gas. ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco

Inc. and Phillips Petroleum Company. The merger between Conoco and Phillips was consummated on August 30, 2002.

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining,

marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology

operations included in our Emerging Businesses segment (collectively, our “Downstream business”), were transferred to Phillips 66. As a part of our strategic

asset disposition program, in the fourth quarter of 2012, we agreed to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan)

and our Nigerian and Algerian businesses. Results of operations related to Phillips 66, Kashagan, Nigeria and Algeria have been classified as discontinued

operations in all periods presented in this Annual Report on Form 10-K. For additional information, see Note 2—Discontinued Operations, in the Notes to

Consolidated Financial Statements.

Headquartered in Houston, Texas, we have operations and activities in 30 countries. Our key focus areas include safely operating producing assets, executing

major developments and exploring for new resources in promising areas. Our portfolio primarily includes legacy assets in North America, Europe, Asia and

Australia; growing North American shale and oil sands businesses; several major international developments; and a global exploration program.

At December 31, 2012, ConocoPhillips employed approximately 16,900 people worldwide.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 25—Segment Disclosures and Related Information, in the Notes to Consolidated Financial

Statements, which is incorporated herein by reference.

We explore for, produce, transport and market crude oil, bitumen, natural gas, liquefied natural gas (LNG) and natural gas liquids on a worldwide basis. At

December 31, 2012, our continuing operations were producing in

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the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Malaysia, Qatar, Libya and

Russia.

Our operating segments were realigned upon the separation of Phillips 66, and as a result, all prior periods presented have been restated. We manage our

operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and

Middle East, and Other International.

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

incorporated herein by reference:

• Proved worldwide crude oil, natural gas liquids, natural gas and bitumen reserves.

• Net production of crude oil, natural gas liquids, natural gas and bitumen.

• Average sales prices of crude oil, natural gas liquids, natural gas and bitumen.

• Average production costs per barrel of oil equivalent (BOE).

• Net wells completed, wells in progress and productive wells.

• Developed and undeveloped acreage.

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

Financial Statements. Approximately 80 percent of our proved reserves are located in politically stable countries that belong to the Organization for Economic

Cooperation and Development. Natural gas reserves are converted to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE. See

Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance the understanding of

the table below.

 Millions of Barrels of Oil Equivalent

Net Proved Reserves at December 31 2012 2011 2010 

Crude oil 

Consolidated operations 2,684 2,617 2,496 

Equity affiliates 95 124 177 

Total Crude Oil 2,779 2,741 2,673 

Natural gas liquids 

Consolidated operations 646 670 665 

Equity affiliates 48 51 54 

Total Natural Gas Liquids 694 721 719 

Natural gas 

Consolidated operations 2,726 2,933 3,039 

Equity affiliates 543 553 580 

Total Natural Gas 3,269 3,486 3,619 

Bitumen 

Consolidated operations 506 530 455 

Equity affiliates 1,394 909 844 

Total Bitumen 1,900 1,439 1,299 

Total consolidated operations 6,562 6,750 6,655 

Total equity affiliates 2,080 1,637 1,655 

Total company 8,642 8,387 8,310 

In 2012, worldwide production, including our share of equity affiliates, was 1,578 thousand barrels of oil equivalent per day (MBOED), a 3 percent decrease

from 2011 production of 1,619 MBOED. Production from continuing operations for 2012 averaged 1,527 MBOED, compared with 1,561 MBOED in

2011. Average production from continuing operations decreased 2 percent in 2012, primarily as a result of normal field decline, the impact from asset

dispositions and higher planned and unplanned downtime. These decreases were largely offset by additional production from major developments, mainly

from shale plays in the Lower 48 and ramp-up of new phases at FCCL, the resumption of production in Libya following a period of civil unrest in 2011, and

increased drilling programs in the Lower 48.

Our worldwide annual average crude oil sales price from continuing operations remained relatively flat in 2012, from $105.52 per barrel in 2011 to $105.72

per barrel in 2012, while worldwide average annual natural gas liquids prices from continuing operations decreased 17 percent, from $55.73 per barrel in

2011 to $46.36 per barrel in 2012. Our average annual worldwide natural gas sales price from continuing operations decreased 6 percent, from $5.80 per

thousand cubic feet in 2011 to $5.48 per thousand cubic feet in 2012. Average annual bitumen prices decreased 14 percent, from $62.56 per barrel in 2011 to

$53.91 per barrel in 2012.

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ALASKA

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. In 2012, Alaska

operations contributed 24 percent of our worldwide liquids production and 1 percent of our natural gas production.

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural 

Gas

MMCFD 

Total

MBOED

Average Daily Net Production 

Greater Prudhoe Area 36.1% BP 104 5 105 

Greater Kuparuk Area 52.2-55.4 ConocoPhillips 54 - 54 

Western North Slope 78 ConocoPhillips 46 1 46 

Cook Inlet Area 33.3-100 ConocoPhillips - 49 8 

Total Alaska 204 5 5 213 

(1) Thousands of barrels per day.

(2) Millions of cubic feet per day.

Greater Prudhoe Area

The Greater Prudhoe Area includes the Prudhoe Bay Field and five satellite fields, as well as the Greater Point McIntyre Area fields. Prudhoe Bay, the largest oil

field on Alaska’s North Slope, is the site of a large waterflood and enhanced oil recovery operation, as well as a gas processing plant which processes natural

gas for reinjection into the reservoir. Prudhoe Bay’s satellites are Aurora, Borealis, Polaris, Midnight Sun and Orion, while the Point McIntyre, Niakuk,

Raven and Lisburne fields are part of the Greater Point McIntyre Area.

Greater Kuparuk Area

We operate the Greater Kuparuk Area, which is made up of the Kuparuk Field and four satellite fields: Tarn, Tabasco, Meltwater and West Sak. Kuparuk is

located 40 miles west of Prudhoe Bay on Alaska’s North Slope. Field installations include three central production facilities that separate oil, natural gas and

water, as well as a separate seawater treatment plant. The natural gas is either used for fuel or compressed for reinjection.

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 2012, Alpine West CD5, a satellite field located west of Alpine in the National Petroleum Reserve—Alaska

(NPRA), was sanctioned. Initial production is anticipated in late 2015, with net peak production estimated at 10 MBOED in 2016.

Cook Inlet Area

We operate the North Cook Inlet Unit, the Beluga River Unit, and the Kenai LNG Plant in the Cook Inlet Area. We have a 100 percent interest in the North

Cook Inlet Unit and the Kenai LNG Plant, while we own 33.3 percent of the Beluga River Unit. Our share of production is sold to local utilities and is also

used to supply feedstock and fuel to the Kenai LNG Plant.

The Kenai LNG Plant had historically supplied LNG to utility companies in Japan. Although we idled the plant in October 2012, we maintain the capability

to operate it and are evaluating options for future use. The LNG export license will expire in March 2013.

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Point Thomson

We own a 5 percent interest in the Point Thomson Field, which is located approximately 60 miles east of Prudhoe Bay. An initial production system is

anticipated to be online by 2016, which is estimated to send 400 net BOED of condensate through the Trans-Alaska Pipeline System (TAPS).

North Slope Natural Gas

In March 2012, we, along with Exxon Mobil Corporation, BP p.l.c. and TransCanada Corporation, announced we are working together on a plan aimed at

commercializing North Slope natural gas resources through large-scale LNG exports from south-central Alaska. Planning and assessment is ongoing.

Exploration

In the February 2008 Outer Continental Shelf (OCS) Lease Sale 193, we successfully bid and were awarded 10-year-primary-term leases on 98 blocks in the

Chukchi Sea. We plan to drill an exploration well on our Devil’s Paw prospect in 2014, subject to the outcome of pending litigation challenging Lease Sale 193

and the receipt of required regulatory permits.

Shark Tooth #1, an appraisal step-out well from the southwestern area of the Kuparuk Field, was spud in January 2012, and is being evaluated for further

development potential. During 2013, we plan to drill one exploration well, Cassin, on the North Slope.

Transportation

We transport the petroleum liquids produced on the North Slope to south-central Alaska through an 800-mile pipeline that is part of TAPS. We have a

28.3 percent ownership interest in TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok Pipelines on the North Slope.

Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope production, using five company-owned doublehulled tankers in addition to chartering third-party vessels as necessary.

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LOWER 48 AND LATIN AMERICA

Lower 48

The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states. We hold 15.5 million net onshore and offshore

acres in the Lower 48. In 2012, Lower 48 and Latin America contributed 25 percent of our worldwide liquids production and 37 percent of our natural gas

production.

 2012

 

 Interest Operator 

 Liquids

MBD

 

 

Natural

Gas

MMCFD

 

 

 

Total

MBOED

 

 

Average Daily Net Production 

Eagle Ford Various % Various 5 6 85 70 

Bakken Various Various 22 17 25 

Barnett Various Various 6 49 14 

Permian Various Various 33 111 51 

San Juan Various Various 49 750 174 

Lobo Various ConocoPhillips 5 112 24 

Anadarko Basin Various Various 6 124 27 

Wind River Various Various - 78 13 

Bossier Various Various - 43 7 

Other onshore Various Various 18 111 37 

Gulf of Mexico Various Various 13 13 15 

Total U.S. Lower 48 208 1,493 457 

Onshore

We hold 13.8 million net acres of onshore conventional and unconventional acreage in the Lower 48. Our unconventional holdings total 2.5 million net acres

and include approximately 626,000 net acres in the Bakken; 227,000 net acres in the Eagle Ford; 194,000 net acres in Permian; 130,000 net acres in

Niobrara; 900,000 net acres in the San Juan Basin; and nearly 430,000 net acres in other unconventional exploration plays. The majority of this acreage is

either held by production or owned by the Company.

The majority of our 2012 onshore production originated from the San Juan Basin, Permian Basin, Eagle Ford, Bakken, Barnett, the Lobo Trend, Anadarko

Basin and Bossier Trend. We also have operations in the Wind River Basin, East Texas, Rockies and northern and southern Louisiana. Onshore activities in

2012 were centered mostly on continued optimization and development of existing and emerging assets, with particular focus on areas with higher liquids

production.

• Shale Plays

Exploration and development continued in our shale positions in the Eagle Ford, Bakken and Barnett. In the Eagle Ford, we drilled 211

exploration and development wells and connected 170 wells in 2012, achieving net peak production of over 100 MBOED in December 2012. In

2013, we plan to drill approximately 140 wells and connect approximately 200 wells. With continued investments, we expect long-term average

production from the Eagle Ford will be approximately 140 MBOED by 2016.

• San Juan

The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, includes significant conventional gas production, which

yields approximately 35 percent natural gas liquids, as well as the majority of our U.S. coalbed methane (CBM) production. We hold

approximately 1.3 million acres of oil and gas leases by production in San Juan, where we continue to pursue

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conventional development opportunities. This includes approximately 900,000 net acres of lease rights, where we are advancing the assessment of

the Mancos shale play.

In January 2013, we entered into an agreement to sell the majority of our properties in the Cedar Creek Anticline, comprising approximately 86,000 net acres in

southwestern North Dakota and eastern Montana. The transaction is expected to close in the first quarter of 2013.

Gulf of Mexico

At year-end 2012, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one operated field and three fields operated by coventurers, including:

• 75 percent operator interest in the Magnolia Field in Garden Banks Blocks 783 and 784.

• 16 percent nonoperator interest in the unitized Ursa Field located in the Mississippi Canyon Area.

• 16 percent nonoperator interest in the Princess Field, a northern, subsalt extension of the Ursa Field.

• 12.4 percent nonoperator interest in the unitized K2 Field, comprised of seven blocks in the Green Canyon Area.

Exploration

• Conventional Exploration

In the deepwater Gulf of Mexico, we held 1.7 million acres at December 31, 2012. In November 2012, we were the successful high bidder on 62

blocks in OCS Western Lease Sale 229, the majority of which have been awarded to date. We anticipate the remaining blocks will be awarded in

the first quarter of 2013, which would increase our Gulf of Mexico position to 2.0 million net acres. In 2013, drilling continued on the partneroperated Coronado wildcat well and the Shenandoah appraisal well, both of which were spud in 2012. During the first half of 2013, drilling is

expected to commence on the partner-operated Ardennes wildcat well, the Tiber appraisal well and a ConocoPhillips-operated wildcat well in the

Miocene/Pliocene Thorn prospect. We also plan to participate in two-to-three additional non-operated wildcat wells in 2013.

In support of our intentions to grow our Gulf of Mexico exploration program, we secured access to an ultra deepwater drillship in 2012, which

will provide rig availability for our operated drilling program beginning in 2014.

• Unconventional Exploration

In 2012, we actively pursued the appraisal of our existing unconventional resource plays, including the Eagle Ford in South Texas, the Bakken in

the Williston Basin, the Barnett in the Fort Worth Basin, the Niobrara play in the Denver-Julesburg Basin, the Avalon and Wolfcamp in the

Permian Basin, and the Mancos in the San Juan Basin. During 2012, we acquired approximately 340,000 net additional acres in various resource

plays across the Lower 48, which included the Avalon, Wolfcamp, Niobrara, and various exploration plays, further expanding our significant

acreage position in Lower 48 shale plays to approximately 2.5 million net acres.

During 2012, we drilled a total of 20 unconventional test wells in the Avalon, Wolfcamp, Niobrara, Bakken Little Missouri, Lewis and Mancos

plays. Drilling is expected to continue in 2013.

Transportation

Our 25 percent interest in the Rockies Express Pipeline (REX) was transferred to Phillips 66 as part of the separation. We retained the capacity rights and

obligations to REX.

Facilities

Freeport LNG Terminal

We have a long-term agreement with Freeport LNG Development, L.P. to use 0.9 billion cubic feet per day of regasification capacity at Freeport’s 1.5-billioncubic-feet-per-day LNG receiving terminal in Quintana, Texas.

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Market conditions currently favor the flow of LNG to European and Asian markets; therefore, our near- to mid-term utilization of the Freeport Terminal is

expected to be limited to LNG storage and reload activities. We are responsible for monthly process-or-pay payments to Freeport irrespective of whether we

utilize the terminal for regasification. The financial impact of these capacity underutilization payments is not expected to be material to our future earnings or

cash flows.

Golden Pass LNG Terminal

We have a 12.4 percent ownership interest in the Golden Pass LNG Terminal and affiliated Golden Pass Pipeline. It is located adjacent to the Sabine-Neches

Industrial Ship Channel northwest of Sabine Pass, Texas. The terminal became commercially operational in May 2011. We hold terminal and pipeline

capacity for the receipt, storage and regasification of the LNG purchased from Qatargas 3 and the transportation of regasified LNG to interconnect with major

interstate natural gas pipelines. Market conditions currently favor the flow of LNG to European and Asian markets; therefore, our near-to-mid-term utilization

of the terminal is expected to be limited.

Phoenix Park Gas Processors Limited

We own a 39 percent interest in Phoenix Park Gas Processors Limited, which processes natural gas in Trinidad and markets natural gas liquids in the

Caribbean, Central America and the U.S. Gulf Coast. Facilities include a 2-billion-cubic-feet-per-day gas processing plant and a 70,000 barrel-per-day natural

gas liquids fractionator.

Other

• San Juan Gas Plant – We operate and own a 50 percent interest in the San Juan Gas Plant, a 550 million cubic-feet-per-day capacity natural gas

processing plant in Bloomfield, New Mexico.

• Lost Cabin Gas Plant – We operate and own a 46 percent interest in the Lost Cabin Gas Plant, a 313 million cubic-feet-per-day capacity natural gas

processing facility in Lysite, Wyoming.

• Wingate Fractionator – We operate and own the Wingate Fractionator, a 25,000 barrel-per-day capacity natural gas liquids fractionation plant located

in Gallup, New Mexico.

Venezuela

In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan

government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed

control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this

expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment

Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010, and we anticipate an interim decision on key legal

and factual issues in 2013. In a separate commercial arbitration from the Company’s ICSID claim discussed above, an International Chamber of Commerce

(ICC) tribunal issued a decision in favor of the Company in September 2012, finding PDVSA owed $67 million for pre-expropriation breaches of the

Petrozuata project agreements. In November 2012, based on the ICC tribunal ruling, PDVSA paid ConocoPhillips $68 million, including post-judgment

interest, which resulted in a $61 million after-tax earnings increase. The Company also recognized additional income of $173 million after-tax associated with

the reversal of a related contingent liability accrual.

Ecuador

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a

result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order

issued by ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally seized crude oil. In 2009, Ecuador took

over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation

claim. On April 24, 2012, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe are not material. The ICSID tribunal

issued a decision on liability on December 14, 2012, in favor of Burlington,

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finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional

arbitration phase will take place to determine the damages owed to ConocoPhillips for Ecuador’s actions.

Peru

Exploration

We own a 45 percent operating interest in Blocks 123 and 129, covering nearly 1.6 million net acres. In October 2012, we announced our decision not to

pursue further exploration activities in Blocks 123 and 129. This decision to withdraw is part of our strategic plan to optimize our portfolio of assets.

CANADA

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta.

In 2012, Canada operations contributed 15 percent of our worldwide liquids production and 21 percent of our natural gas production.

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Bitumen

MBD 

Total

MBOED

Average Daily Net Production 

Western Canada Various % Various 37 857 - 180 

Surmont 50.0 ConocoPhillips - - 12 12 

Foster Creek 50.0 Cenovus - - 51 51 

Christina Lake 50.0 Cenovus - - 30 30 

Total Canada 37 857 93 273 

Western Canada

Our operations in western Canada are primarily comprised of three core development areas: Deep Basin, Kaybob and O’Chiese, which extend from central

Alberta to northeastern British Columbia. We operate or have ownership interests in approximately 80 natural gas processing plants in the region, and, as of

December 31, 2012, held leasehold rights in 5.9 million net acres in western Canada.

Oil Sands

We hold approximately 1.1 million net acres of land in the Athabasca Region of northeastern Alberta. Our bitumen resources in Canada are produced via an

enhanced thermal oil recovery method called steam-assisted gravity drainage (SAGD), whereby steam is injected into the reservoir, effectively liquefying the

heavy bitumen, which is recovered and pumped to the surface for further processing.

• Surmont

The Surmont oil sands leases are located approximately 35 miles south of Fort McMurray, Alberta. Surmont is a 50/50 joint venture with Total

S.A. Surmont Phase 2 construction began in 2010, with production startup targeted for 2015. Following startup, Surmont’s gross production

capacity is estimated to be 150 MBOED, with net peak production of 65 MBOED anticipated by 2018.

• FCCL

We have a 50/50 heavy oil business venture with Cenovus Energy Inc., FCCL Partnership, a Canadian upstream general partnership. FCCL’s

assets, operated by Cenovus, include the Foster Creek, Christina Lake and Narrows Lake SAGD bitumen developments.

Construction continued in 2012 on both the Foster Creek and Christina Lake properties. At Christina Lake, Phase D was completed and

production came on stream in the third quarter of 2012. Phase D

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added 40 MBOED of gross production capacity, bringing total gross production capacity to 98 MBOED. Phase E is expected to be completed in

2013, with first production targeted for the second half of 2013, which will add another 40 MBOED of gross production capacity. Phase F was

sanctioned in the fourth quarter of 2012, with production startup anticipated in 2016, which will add an additional 50 MBOED of gross

production capacity.

At Foster Creek, construction progressed on Phases F, G and H, which are estimated to be completed in 2014, 2015 and 2016, respectively.

These phases will add approximately 125 MBOED of gross production capacity. FCCL anticipates submitting an application for regulatory

approval for an additional expansion, Phase J, in 2013.

Narrows Lake is a new oil sands development within the FCCL Partnership. In May 2012, FCCL received approval from the Alberta government

to proceed with Narrows Lake. Narrows Lake Phase A was sanctioned in the fourth quarter of 2012, and initial production is anticipated in

2017.

Parsons Lake/Mackenzie Gas Project

We were involved with three other energy companies, as members of the Mackenzie Gas Project, on the development of the Mackenzie Valley Pipeline and

gathering system, which was proposed to transport onshore gas production from the Mackenzie Delta in northern Canada to established markets in North

America. We have a 75 percent interest in the Parsons Lake natural gas field, one of the primary fields in the Mackenzie Delta, which would anchor the

pipeline development. Due to a continued decline in market conditions and lack of acceptable commercial terms, the project was suspended indefinitely in the

first quarter of 2012. As a result, we recorded a $520 million after-tax impairment in 2012 for the carrying value of capitalized development costs and

associated undeveloped leasehold costs.

Amauligak

We have a 53.8 percent operating interest in Amauligak, which lies approximately 31 miles offshore in shallow water in the Beaufort Sea. A range of

development options are being evaluated.

Exploration

We hold exploration acreage in four areas of Canada: offshore eastern Canada, onshore western Canada, the Mackenzie Delta/Beaufort Sea Region and the

Arctic Islands.

• Unconventional Exploration

During 2012, we drilled unconventional test wells in the Duvernay and Montney plays. In 2013, exploration activities will continue in Duvernay,

the Canol Shale in the Northwest Territories, Muskwa in the Horn River Basin and the Montney play. We also plan to continue delineating

potential development opportunities in the oil sands.

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EUROPE

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland

and Greenland. In 2012, operations in Europe contributed 17 percent of our worldwide liquids production and 13 percent of natural gas production.

Norway

 2012

 Liquids Natural Gas Total

 

 Interest Operator MBD MMCFD MBOED

Average Daily Net Production 

Greater Ekofisk Area 35.1 % ConocoPhillips 6 6 52 75 

Alvheim 20 Marathon 14 14 16 

Heidrun 24 Statoil 11 10 13 

Other Various Various 17 84 31 

Total Norway 108 160 135 

The Greater Ekofisk Area, located approximately 200 miles offshore Stavanger, Norway in the North Sea, is comprised of four producing fields: Ekofisk,

Eldfisk, Embla and Tor. Crude oil is exported to Teesside, England, and the natural gas is exported to Emden, Germany. The Ekofisk South and Eldfisk II

developments continue, with production expected in the fourth quarters of 2013 and 2014, respectively.

The Alvheim development consists of a floating production, storage and offloading (FPSO) vessel and subsea installations. Produced crude oil is exported via

shuttle tankers, and natural gas is transported to the United Kingdom via a pipeline to the Beryl-Sage system.

The Heidrun Field is located in the Norwegian Sea. Produced crude oil is transported to Mongstad in Norway and Tetney in the United Kingdom by doublehulled shuttle tankers. Part of the natural gas is transported and sold to buyers in Europe, while the remainder is used as feedstock in a methanol plant in

Norway, in which we own an 18.3 percent interest.

We also have varying ownership interests in five other producing fields in the Norway sector of the North Sea and in the Norwegian Sea.

In the second quarter of 2012, we sold our Norway and U.K. interests in the Statfjord Field and associated satellites.

Exploration

During 2012, we completed the evaluation of available acreage for the 22 Licensing Round and submitted an application in December.

Transportation

We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil from Ekofisk to a crude oil stabilization and

natural gas liquids processing facility in Teesside, England. In addition, we own a 1.9 percent interest in Norwegian Continental Shelf Gas Transportation

(Gassled), which owns most of the Norwegian gas transportation infrastructure.

11

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United Kingdom

 2012

 

 Interest Operator 

 Liquids

MBD

 

 

Natural

Gas

MMCFD

 

 

 

Total

MBOED

 

 

Average Daily Net Production 

Britannia 58.7 % Britannia 4 117 24 

 Operator Ltd. 

Britannia Satellites 75.0-83.5 ConocoPhillips 13 23 17 

J-Area 32.5-36.5 ConocoPhillips 8 5 9 18 

Southern North Sea Various Various - 98 16 

East Irish Sea 100 HRL - 5 6 9 

Other Various Various 9 3 9 

Total United Kingdom 34 356 93 

In addition to our interest in the Britannia natural gas and condensate field, we own 50 percent of Britannia Operator Limited, the operator of the field.

Condensate is delivered through the Forties Pipeline to an oil stabilization and processing plant near the Grangemouth Refinery in Scotland, while natural gas

is transported through Britannia’s line to St. Fergus, Scotland. The Britannia satellite fields, Callanish and Brodgar, produce via subsea manifolds and

pipelines linked to the Britannia platform.

J-Area is comprised of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. Development of the Jasmine Field continued during

2012, and we anticipate first production in the fourth quarter of 2013. Jasmine is estimated to achieve average net peak production of 37 MBOED in 2014.

We have various ownership interests in 18 producing gas fields in the Rotliegendes and Carboniferous areas of the Southern North Sea. Our interests in the

East Irish Sea include the Millom, Dalton and Calder fields, which are operated on our behalf by a third party.

We own a 24 percent interest in the Clair Field, located in the Atlantic Margin. The development of Clair Ridge received government approval in October 2011,

and initial production is estimated to occur in 2016.

We sold our interest in the Alba Field in the second quarter of 2012.

Exploration

We were awarded three licenses during 2012, one in the East Irish Sea and two in the Central Graben, North Sea. We approved the Greater Clair exploration

and appraisal program in 2012 and plan to commence drilling in 2013.

Transportation

We have a 10 percent interest in the Interconnector Pipeline, which links the United Kingdom and Belgium and facilitates the marketing throughout Europe of

natural gas produced in the United Kingdom. In January 2013, we entered into an agreement to sell our equity interest. The sale is expected to close in the first

quarter of 2013.

We operate the Teesside oil and Theddlethorpe gas terminals in which we have 29.3 percent and 50 percent ownership interests, respectively. We also have a

100 percent ownership interest in the Rivers Gas Terminal, operated by a third party, in the United Kingdom.

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Poland

Exploration

We are participating in a shale gas venture in Poland. In the third quarter of 2012, we exercised our option to acquire a 70 percent interest in Lane Energy

Poland and assumed operatorship for three western Baltic Basin concessions. Four wells have been drilled on these concessions, with further well tests and

drilling planned for 2013. A 3-D seismic survey is also planned for the first quarter of 2013.

Greenland

Exploration

During 2012, we successfully completed a 2-D seismic survey in Block 7011/11 of the Qamut license in West Greenland and recovered stratigraphic cores

which will guide the interpretation of this new data. In addition, we have completed the evaluation of available acreage in East Greenland.

ASIA PACIFIC AND MIDDLE EAST

The Asia Pacific and Middle East segment has exploration and production operations in China, Indonesia, Malaysia, Australia and the Timor Sea; producing

operations in Qatar; and exploration activities in Bangladesh and Brunei. In 2012, operations in the Asia Pacific and Middle East segment contributed 13

percent of our worldwide liquids production and 28 percent of natural gas production.

Australia and Timor Sea

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Total

MBOED

Average Daily Net Production 

Australia Pacific LNG 37.5 % Origin Energy - 118 20

Bayu-Undan 56.9 ConocoPhillips 27 195 5 9

Athena/Perseus 50 ExxonMobil - 35 6

Total Australia and Timor Sea 27 348 85

Australia Pacific LNG

Australia Pacific LNG Pty Ltd (APLNG), our joint venture with Origin Energy and China Petrochemical Corporation (Sinopec), is focused on producing

CBM from the Bowen and Surat basins in Queensland, Australia. Origin operates APLNG’s production and pipeline system, and we will operate the LNG

facility. Natural gas is currently sold to domestic customers, while progress continues on the development of an LNG processing and export sales business.

Once established, this will enhance our LNG position and serve as an additional LNG hub supplying Asia Pacific markets. Two initial 4.5-million-tonnesper-year LNG trains have been sanctioned, with approximately 9,000 net wells ultimately envisioned to supply both the domestic gas market and the LNG

development. The additional wells will be supported by expanded gas gathering systems, centralized gas processing and compression stations, and water

treatment facilities, in addition to a new export pipeline from the gas fields to the LNG facilities.

During 2011, three significant milestones were achieved. First, the development received environmental approval from the Australian federal government.

Second, definitive agreements were signed with Sinopec for the supply of up to 4.3 million tonnes of LNG per year for 20 years. The agreements also specified

terms under which Sinopec subscribed for a 15 percent equity interest in APLNG, with both our ownership interest and Origin Energy’s ownership interest

diluting from 50 percent to 42.5 percent. The Subscription Agreement was completed in August 2011. Third, a binding Heads of Agreement was signed with

Japan-based Kansai Electric Power Co. Inc., for the sale of approximately 1 million tonnes of LNG per year for 20 years.

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In January 2012, APLNG and Sinopec signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million

tonnes of LNG per year through 2035. This agreement, in combination with the Kansai Electric agreement, finalized the marketing of the second train. In July

2012, we sanctioned the development of the second 4.5-million-tonnes-per-year LNG production train. Start-up of the second train is expected to occur in the

fourth quarter of 2015, with resulting LNG exports commencing shortly thereafter sold under the binding sales agreements to Sinopec and Kansai Electric.

Upon sanctioning of the second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed to additional shares in APLNG, which

increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin Energy’s ownership interest

diluted from 42.5 percent to 37.5 percent.

APLNG executed project financing agreements for an $8.5 billion project finance facility during the third quarter of 2012 and began drawing on the financing

in October 2012. Our reduced ownership interest, coupled with Sinopec’s $2.1 billion injection into APLNG associated with the dilution and APLNG’s

successful placement of the $8.5 billion of project financing, will lower our future capital requirements to fund the project. We are evaluating opportunities to

further reduce our ownership interest in APLNG. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata

share of the project finance facility, which will be released upon meeting certain completion milestones.

For additional information, see Note 3—Variable Interest Entities (VIEs), Note 6—Investments, Loans and Long-Term Receivables, and Note 13

—Guarantees, in the Notes to Consolidated Financial Statements.

Bayu-Undan

The Bayu-Undan gas condensate field is located in the Timor Sea Joint Petroleum Development Area between Timor-Leste and Australia. We also operate and

own a 56.9 percent interest in the associated Darwin LNG Facility, located at Wickham Point, Darwin. Produced natural gas is used to supply the Darwin

LNG Plant. In 2012, we sold 148 billion gross cubic feet of LNG to utility customers in Japan.

During the first half of 2013, the Bayu-Undan Phase 3 Development will focus on procuring long-lead items and securing contracts for a semi-submersible

drilling rig. Final Investment Decision is expected in mid-2013 and will be followed by further detailed engineering and procurement activities. Drilling is

anticipated to commence in the second quarter of 2014.

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax

assessments. Between 2010 and 2012, ConocoPhillips has paid, under protest, tax assessments totaling approximately $227 million, which are primarily

recorded in the “Investments and long-term receivables” line on our December 31, 2012, consolidated balance sheet. The arbitration will be conducted in

Singapore 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. The arbitration process is currently underway. Future impacts on our business are not known at this time.

Athena/Perseus

The Athena production license (WA-17-L) is located offshore Western Australia and contains part of the Perseus Field which straddles the boundary with WA1-L, an adjoining license area. Natural gas is produced from these licenses.

Greater Sunrise

We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor Sea. Although the Sunrise Joint Venture and the governments

of Australia and Timor-Leste are aligned with the objective to develop the Greater Sunrise Field, key challenges must be resolved before significant funding

commitments can be made. These include gaining agreement between both governments and the joint venture on a development concept.

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Exploration

• Conventional Exploration

We operate three permits located in the Browse Basin, offshore northwest Australia. We own a 60 percent interest in two of the permits, WA-315-P

and WA-398-P, and a 10 percent interest in WA-314-P. Phase I of the 2009/2010 drilling campaign resulted in discoveries in WA-315-P and WA398-P. Phase II of the drilling campaign, expected to consist of a five-to-eight well program, commenced in 2012. The first well, Boreas-1,

discovered hydrocarbons and was completed, plugged and abandoned in 2012. The second well, Zephyros-1, is currently being drilled and is

expected to reach targeted depth in the first quarter of 2013.

In the Bonaparte Basin, offshore northern Australia, we operate and own interests in three permits, NT/RL5, NT/P69 and NT/P61. In 2012, we

farmed-down our interest from 60 percent to 37.5 percent. A three-well appraisal program is expected to commence in 2014.

• Unconventional Exploration

In September 2011, we executed a farm-in agreement to acquire a 75 percent working interest in four exploration permits: EP-443, EP-450, EP-451

and EP-456, which cover approximately 11 million gross acres in the Canning Basin of Western Australia. In 2012, our 75 percent interest in the

permits was approved, and Phase I of a three-well drilling program commenced in the third quarter of 2012 with the drilling of the first well,

Nicolay-1. The second well, Gibb-Maitland-1, was spud in December 2012. Upon completion of the Phase I drilling program, we will have the

right to assume operatorship of the exploration permits.

Indonesia

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Total

MBOED

Average Daily Net Production 

South Natuna Sea Block B 40.0 % ConocoPhillips 12 115 31 

South Sumatra 45.0-54.0 ConocoPhillips 2 322 56 

Total Indonesia 14 437 87 

We operate four production sharing contracts (PSCs) in Indonesia: the offshore South Natuna Sea Block B and three onshore PSCs, the Corridor Block and

South Jambi “B”, both located in South Sumatra, and Warim in Papua. Our producing assets are primarily concentrated in two core areas: South Natuna Sea

and onshore South Sumatra.

South Natuna Sea Block B

The offshore South Natuna Sea Block B PSC has 2 producing oil fields and 16 natural gas fields in various stages of development. Natural gas production

is sold under international sales agreements to Malaysia and Singapore.

South Sumatra

The Corridor PSC consists of six oil fields and six 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. The South Jambi “B” PSC includes three

gas fields in various stages of development.

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Exploration

We own and operate an 80 percent interest in the Warim onshore exploration PSC in Papua. During 2012, we relinquished the Kuma and Arafura Sea offshore

exploration PSCs.

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

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Total

MBOED

Average Daily Net Production 

Peng Lai 49.0 % ConocoPhillips 30 3 31 

Panyu 24.5 CNOOC 9 - 9 

Total China 39 3 40 

The Peng Lai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05. Production from the Phase I development of the PL 19-3 Field began in 2002.

The Phase II development includes six drilling and production platforms and an FPSO vessel used to accommodate production from all the fields.

In January 2012, we and the China National Offshore Oil Corp. (CNOOC) announced an agreement with China’s Ministry of Agriculture to resolve fisheryrelated issues in connection with two separate seepage incidents which occurred near the Peng Lai 19-3 Platforms B and C in 2011. Under this agreement,

approximately $160 million was paid as compensation to settle private claims of potentially affected fishermen in relevant Bohai Bay communities, and

public claims for alleged fishery damage. The agreement fulfills the objectives of the compensation fund we announced in September 2011. As part of this

agreement, we have also designated approximately $16 million of our previously announced environmental fund to be used to improve fishery resources and

for related projects.

In April 2012, we and CNOOC announced an agreement with China’s State Oceanic Administration (SOA) related to claims for possible impacts of the Peng

Lai 19-3 seepage incidents on the Bohai Bay marine environment. Under this agreement, approximately $173 million will be paid to resolve claims, and

approximately $18 million will be paid to support environmental initiatives focused on improving marine environment protection in Bohai Bay. Of the total

$191 million, $86 million was paid in 2012.

We hold a 49 percent ownership interest in the Peng Lai fields.

The SOA required implementation of preventative measures to avoid recurrence of the incidents, in addition to the filing of an updated environmental impact

assessment (EIA) and overall development plan (ODP) for approval. A revised ODP was submitted to China’s National Development and Reform Commission

in November 2011, and a revised EIA was submitted to the SOA in February 2012. The EIA was approved in October 2012, and the ODP was approved in

December 2012. In February 2013, we received notification from the SOA, which granted approval for a step-by-step resumption of normal production

operations at the Peng Lai 19-3 Field in Bohai Bay.

The Panyu development, located in the South China Sea, is comprised of three oil fields: Panyu 4-2, Panyu 5-1 and Panyu 11-6. During 2012, a production

platform was added to each of the Panyu 4-2 and Panyu 5-1 fields. Production from the new platforms began in September 2012.

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Exploration

• Unconventional Exploration

In 2012, we entered into an agreement with Sinopec Southern Exploration Company to execute a joint study over the Qijiang Shale Gas Block,

located in the Sichuan Basin. The Qijiang Shale Gas Block covers an area of 3,917 square kilometers. The study, which will be carried out over

two years and includes seismic and drilling obligations, will be an important step in evaluating the potential for shale gas exploration in the area.

Malaysia

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Total

MBOED

Average Daily Net Production 

Gumusut 33.0 % Shell 1 - 1 

Total Malaysia 1 - 1 

We own interests in four deepwater PSCs located off the eastern Malaysian state of Sabah: Block G, Block J, the Kebabangan (KBB) Cluster and SB-311.

We have a 35 percent interest in Block G; 40 percent in Block J; 30 percent in KBB; and 40 percent in SB-311. First production from Gumusut, located in

Block J, occurred in the fourth quarter of 2012. Production from a permanent, semi-submersible floating production and storage vessel is expected in late

2013, with estimated net annual peak production of 32 MBOED anticipated in 2014. The development of the KBB gas field commenced in 2011, with first

production anticipated in late 2014. Estimated net annual peak production from KBB of 29 MBOED is expected in 2015. Development of the Siakap NorthPetai oil field began in 2012, and first production is expected in late 2013. The Malikai oil field, sanctioned in the fourth quarter of 2012, is the fourth field

under development. First production is anticipated in early 2017.

Exploration

In December 2012, we were formally awarded operatorship of exploration block SB-311, offshore Sabah. A two-well drilling program is planned for this

block, and we expect to complete seismic reprocessing and acquisition in 2013.

Vietnam

We sold our Vietnam business in the first quarter of 2012. Net production averaged 3 MBOED in 2012.

Bangladesh

Exploration

In 2009, we were formally awarded two deepwater blocks in the Bay of Bengal, offshore Bangladesh. We received government approval of the PSC terms in

June 2011 and hold 100 percent interests in Blocks 10 and 11. In 2012, we performed 2-D seismic activities and are currently evaluating the results.

Brunei

Exploration

We have a 6.25 percent working interest in Block CA-2. Two exploration wells were expensed as dry holes in 2011. Exploration activities continued during

2012, and we plan to drill a third well in 2013.

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Qatar

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Total

MBOED

Average Daily Net Production 

Qatargas 3 30.0 % Qatargas Operating Co. 23 367 84 

Total Qatar 23 367 84 

Qatargas 3 (QG3) is an integrated development jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd.

(1.5 percent). QG3 is comprised of upstream natural gas production facilities to produce approximately 1.4 billion gross cubic feet per day of natural gas from

Qatar’s North Field over a 25 year life. It also includes a 7.8-million-gross-tonnes-per-year LNG facility, from which LNG is shipped in leased LNG carriers

destined for sale globally. First gas production was achieved in October 2010, and we achieved peak production during 2011.

QG3 executed the development of the onshore and offshore assets as a single integrated development with Qatargas 4 (QG4), a joint venture between Qatar

Petroleum and Royal Dutch Shell plc. This included the joint development of offshore facilities situated in a common offshore block in the North Field, as

well as the construction of two identical LNG process trains and associated gas treating facilities for both the QG3 and QG4 joint ventures. Production from

the LNG trains and associated facilities are combined and shared.

OTHER INTERNATIONAL

The Other International segment includes exploration and producing operations in Libya and Russia, as well as exploration activities in Angola and the

Caspian Sea. In 2012, we agreed to sell our Nigerian and Algerian businesses and our interest in the Republic of Kazakhstan’s North Caspian Sea Production

Sharing Agreement (Kashagan). As such, results of these operations have been reclassified to discontinued operations for all periods presented. During 2012,

operations in Other International contributed 6 percent of our worldwide liquids production.

Libya

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Total

MBOED

Average Daily Net Production 

Waha Concession 16.3 % Waha Oil Co. 40 18 43 

Total Libya 40 18 43 

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 temporarily suspended in 2011 during Libya’s period of civil unrest. Production restarted in late 2011 and reached 49 MBOED in

November 2012.

Exploration

We participated in an exploration appraisal program within the Waha Concession in 2012 and are currently evaluating results. We drilled three appraisal wells

during 2012 and completed one exploration well in early 2013.

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Russia

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Total

MBOED

Average Daily Net Production 

Naryanmarneftegaz (NMNG) 30.0 % OOO NMNG 8 - 8 

Polar Lights 50.0 Polar Lights Co. 5 - 5 

Total Russia 13 - 13 

NMNG

We sold our interest in NMNG in the third quarter of 2012.

Polar Lights

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

Angola

Exploration

Effective January 1, 2012, we entered into two PSCs with Angola’s national oil company. We have a 30 percent operating interest in Blocks 36 and 37, both of

which are located in Angola’s subsalt play trend. In 2012, we acquired 3-D seismic data for both ultra-deepwater blocks and are currently evaluating the data.

The first wildcat well is expected to be spud in 2014.

Kazakhstan

Transportation

The Baku-Tbilisi-Ceyhan (BTC) Pipeline transports crude oil from the Caspian Region through Azerbaijan, Georgia and Turkey for tanker loadings at the

port of Ceyhan. We have a 2.5 percent interest in BTC.

Exploration

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

Discontinued Operations

Nigeria

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Total

MBOED

Average Daily Net Production* 

OMLs 60, 61, 62, 63 20.0 % Eni 16 149 40 

Total Nigeria 16 149 40 

*Reclassified to discontinued operations.

We have an interest in four onshore Oil Mining Leases (OMLs). Natural gas is sourced from our proved reserves in the OMLs and provides fuel for a 480-

megawatt gas-fired power plant in Kwale, Nigeria. We have a 20 percent interest in this power plant, which supplies electricity to Nigeria’s national electricity

supplier. In 2012, the plant consumed 12 million net cubic feet per day of natural gas.

We have a 17 percent equity interest in Brass LNG Limited, which plans to construct an LNG facility in the Niger Delta.

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In December 2012, we entered into an agreement to sell our entire Nigerian business. The transaction is expected to close by mid-2013.

Algeria

 2012

 

 Interest Operator 

 Liquids

MBD 

Natural

Gas

MMCFD 

Total

MBOED

Average Daily Net Production* 

Menzel Lejmat North 65.0 % ConocoPhillips 8 - 8 

 L’Organization 

Ourhoud 3.7 Ourhoud 3 - 3 

Total Algeria 11 - 11 

*Reclassified to discontinued operations.

Our activities in Algeria are centered around the following fields in Block 405a: the Menzel Lejmat North Fields (MLN), the Ourhoud Field and the EMK

Field. Crude oil production from MLN and Ourhoud is transported to northern Algerian ports where it is sold. The development of the EMK Field, in which

we own a 16.9 percent interest, was sanctioned in 2009. Startup is anticipated in mid-2013.

In December 2012, we entered into an agreement to sell our entire Algerian business. The transaction is expected to close by mid-2013.

Kazakhstan

In the Caspian Sea, we have an 8.4 percent interest in Kashagan. In November 2012, we announced our intention to sell our entire interest in Kashagan. The

transaction is expected to close by mid-2013, subject to customary governmental approvals.

LUKOIL INVESTMENT

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in

Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.

OTHER

Marketing Activities

Our Commercial organization manages our worldwide commodity portfolio, which mainly includes natural gas, crude oil, bitumen, natural gas liquids and

LNG. Marketing activities are performed through offices in the United States, Canada, Europe and Asia. In marketing our production, we attempt to minimize

flow disruptions, maximize realized prices and manage credit-risk exposure. Commodity sales are generally made at prevailing market prices at the time of

sale. We also purchase third-party volumes to better position the Company to fully utilize transportation and storage capacity and satisfy customer demand.

Natural Gas

Our natural gas production, along with third-party purchased gas, is 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.

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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, China and

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

Spill Containment

Marine Well Containment Company

We are a founding member of the Marine Well Containment Company (MWCC), a non-profit organization formed in 2010 which provides well containment

equipment and technology in the deepwater U.S. Gulf of Mexico. In 2011, MWCC launched an interim containment system designed to improve containment

response capabilities in the event of an underwater well control incident. In 2012, MWCC and the U.S. Bureau of Safety and Environmental Enforcement

announced the successful demonstration of the industry’s ability to respond to a deepwater well control incident in the U.S. Gulf of Mexico. MWCC is

advancing this capability and is currently developing an expanded containment system with significantly increased capacity. The expanded containment

system is expected to be available in 2013.

Subsea Well Response Project

In 2011, we, along with eight leading oil and gas companies, launched the Subsea Well Response Project (SWRP), an initiative designed to enhance the

industry’s capability to respond to international subsea well control incidents. In 2012, SWRP, a non-profit organization based in Stavanger, Norway,

partnered with Oil Spill Response Limited, a non-profit organization in the United Kingdom, in order to develop integrated intervention systems which are

more widely available to the industry. This complements the work being undertaken in the United States by MWCC and also in the United Kingdom by the

Oil Spill Prevention and Response Advisory Group (OSPRAG), enhancing our global well response capabilities. We are also a participant in OSPRAG.

LNG Technology

Our Optimized Cascade LNG liquefaction technology business continues to grow with the demand for new LNG plants. The technology has been applied in

10 LNG trains around the world, with 10 more under construction.

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, 2012. No

difference exists between our estimated total proved reserves for year-end 2011 and year-end 2010, which are shown in this filing, and estimates of these

reserves shown in a filing with another federal agency in 2012.

DELIVERY COMMITMENTS

We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and

determinable quantity. Our Commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract

can be the spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 4 trillion

cubic feet of natural gas, including approximately 600 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 80 million

barrels of crude oil in the future. These contracts have various expiration dates through the year 2028. We expect to fulfill the majority of these delivery

commitments with proved developed reserves. In addition, we anticipate using proved undeveloped reserves and spot market purchases to fulfill these

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.

21

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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 publicly available year-end 2011 reserves statistics, we had the

seventh-largest total of worldwide proved reserves of nongovernment-controlled companies. 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 efficiently operating oil and gas producing properties.

GENERAL

At the end of 2012, we held a total of 784 active patents in 54 countries worldwide, including 319 active U.S. patents. During 2012, we received 15 patents in

the United States and 47 foreign patents. Our products and processes generated licensing revenues of $124 million in 2012. 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 $221 million, $193 million and $172 million in 2012, 2011 and

2010, respectively.

Our Health, Safety and Environment (HSE) organization provides tools and support to our business units and staff groups to help them ensure consistent

health, safety and environmental excellence. In support of the goal of zero incidents, we have implemented an HSE Excellence process, which enables business

units to measure their performance and compliance with our HSE Management System requirements, identify gaps, and develop improvement plans.

Assessments are conducted annually to capture progress and set new targets. We are also committed to continuously improving process safety and preventing

releases of hazardous materials.

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 58 through

62 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized

environmental costs for 2012 and those expected for 2013 and 2014.

Website Access to SEC Reports

Our Internet website address is www.conocophillips.com. Information contained on our Internet website is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished

pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after

such reports are filed with, or furnished to, the U.S. Securities and Exchange Commission (SEC). Alternatively, you may access these reports at the SEC’s

website at www.sec.gov.

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Item 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk

factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common

stock.

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

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 and cash flows and may reduce the amount of these commodities we can produce

economically.

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, 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 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 or reviewed by our personnel. Any

significant future price changes could have a material effect on the quantity and present value of our proved reserves. Future reserve revisions could also result

from changes in, among other things, governmental regulation. 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 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.

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 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:

• The discharge of pollutants into the environment.

• Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas emissions as they are, or may

become, regulated).

• The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes.

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• The dismantlement, abandonment and restoration of our properties and facilities at the end of their useful lives.

• Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil sands reservoirs and shale gas plays.

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.

In addition, in response to the Deepwater Horizon incident, the United States, as well as other countries where we do business, may make changes to their

laws or regulations governing offshore operations that could have a material adverse effect on our business.

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

Actions of the U.S., state, local and foreign governments, through tax and other legislation, executive order and commercial restrictions, could reduce our

operating profitability both in the United States and abroad. In certain locations, governments have imposed or proposed restrictions on our operations; special

taxes or tax assessments; and payment transparency regulations that could require us to disclose competitively sensitive information or might cause us to

violate non-disclosure laws of other countries. 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.

Local political and economic factors in international markets could have a material adverse effect on us. Approximately 56 percent of our hydrocarbon

production from continuing operations was derived from production outside the United States in 2012, and 57 percent of our proved reserves, as of

December 31, 2012, 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 liquids, bitumen, natural gas or LNG pricing and taxation, other political, economic or

diplomatic developments, changing political conditions and international monetary fluctuations.

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

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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 participants. 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

participants may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. Failure by us, or an entity in

which we have a joint venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect

on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

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

We maintain insurance against many, but not all, potential losses or liabilities arising from operating risks. As such, our insurance coverage may not be

sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the

funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of

operations and cash flows.

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

The scope and nature of our operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires,

pipeline interruptions, pipeline ruptures, crude oil spills, severe weather, geological events, labor disputes, or cyber attacks. Our operations are also subject to

the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks. 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.

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.

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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

2012, as well as matters previously reported in our 2011 Form 10-K and our first-, second- and third-quarter 2012 Form 10-Qs that were not resolved prior to

the fourth quarter of 2012. 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 was 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.

New Matters

The New Mexico Environment Department has issued four Notices of Violation (NOVs) to ConocoPhillips alleging a total of twenty individual violations for

failure to comply with air emission recordkeeping, reporting and testing requirements at various natural gas compression operations in northwestern New

Mexico. These violations are alleged to have occurred between 2006 and 2012. The agency is seeking a penalty of over $100,000. We have submitted responses

to all four of the NOVs and will work with the agency to resolve these matters.

Matters Previously Reported – ConocoPhillips

The North Dakota Department of Health has requested all the operators in the Bakken Pool area, including ConocoPhillips, enter into an Administrative

Consent Agreement to resolve alleged historic violations of the state’s air emission regulations. The state is proposing a penalty of $2,000 per well drilled in the

Bakken Pool which would result in total penalty to the company of over $100,000. ConocoPhillips is working with the state to resolve this matter.

Matters Previously Reported – Phillips 66

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66.

In connection with the separation, we entered into an Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us

and established procedures for handling claims subject to indemnification and related matters, such as legal proceedings. We have included matters where we

remain a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim

against us.

On September 19, 2012, the Bay Area Air Quality Management District (District) issued a $213,500 demand to settle fourteen NOVs issued in 2009 and

2010 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery. Phillips 66 is working with the District to

resolve this matter.

On October 15, 2012, the District issued a $313,000 demand to settle thirteen NOVs issued in 2010 and 2011 with respect to alleged violations of regulatory

and/or permit requirements at the Phillips 66 Rodeo Refinery. Phillips 66 is working with the District to resolve this matter.

On March 7, 2012, the District issued a $302,500 demand to settle five NOVs issued between 2008 and 2010 to the Phillips 66 Rodeo Refinery. The NOVs

allege non-compliance with the District rules and/or facility permit conditions. Phillips 66 is working with the District to resolve this matter.

In May 2012, the Illinois Attorney General’s office filed and served a Complaint against ConocoPhillips with respect to operations at the Phillips 66 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

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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. Phillips 66 is working with the Illinois Environmental Protection Agency and Attorney General’s office to resolve these

allegations.

In December 2011, ConocoPhillips was notified by the U.S. Environmental Protection Agency (EPA) of alleged violations related to the use of Renewable

Identification Numbers (RINs). Phillips 66 was one of several companies who entered Administrative Settlement Agreements (ASAs) with the EPA to settle

allegations it had used invalid RINs for its 2010 and 2011 fuel program compliance. Under this Agreement, Phillips 66 will pay a maximum of $350,000 in

penalties for the use of invalid RINs. Payments are made upon demand from the EPA. To date, $250,000 has been paid and it is anticipated the EPA will

demand the final $100,000 in 2013.

On November 28, 2011, the Phillips 66 Borger Refinery received a Notice of Enforcement from the Texas Commission on Environmental Quality (TCEQ)

for alleged emissions events that occurred during inclement weather in January and February 2011. The TCEQ is seeking a penalty of $120,000. Phillips 66

is working with TCEQ to resolve this matter.

In October 2011, ConocoPhillips was notified by the Attorney General of the State of California it was conducting an investigation into possible violations of

the regulations relating to the operation of underground storage tanks at gas stations in California. On January 3, 2013, we were served with a lawsuit filed by

the California Attorney General that alleges such violations. Philips 66 is contesting these allegations.

In October 2007, we received a Complaint from the EPA alleging violations of the Clean Water Act related to a 2006 oil spill at the Phillips 66 Bayway

Refinery and proposing a penalty of $156,000. Phillips 66 is working with the EPA and the U.S. Coast Guard to resolve this matter.

On May 19, 2010, the Phillips 66 Lake Charles Louisiana Refinery received a Consolidated Compliance Order and Notice of Potential Penalty from the

Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations, as well as certain provisions of the

consent decree in Civil Action No. H-01-4430. Phillips 66 is working with the LDEQ to resolve this matter.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

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EXECUTIVE OFFICERS OF THE REGISTRANT

Name Position Held Age*

Ellen R. DeSanctis Vice President, Investor Relations and Communications 5 6

Sheila Feldman Vice President, Human Resources 58

Matt J. Fox Executive Vice President, Exploration and Production 52

Alan J. Hirshberg Executive Vice President, Technology and Projects 51

Janet L. Kelly Senior Vice President, Legal, General Counsel and Corporate Secretary 5 5

Ryan M. Lance Chairman of the Board of Directors and Chief Executive Officer 50

Glenda M. Schwarz Vice President and Controller 47

Jeff W. Sheets Executive Vice President, Finance and Chief Financial Officer 5 5

Don E. Wallette, Jr. Executive Vice President, Commercial, Business Development and Corporate Planning 54

*On February 15, 2013.

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 14, 2013.

Set forth below is information about the executive officers.

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.

Sheila Feldman was appointed Vice President, Human Resources in May 2012. She was previously employed by Arch Coal, Inc. and served as Vice

President, Human Resources since 2003.

Matt J. Fox was appointed Executive Vice President, Exploration and Production in May 2012. Prior to that, he was employed by Nexen, Inc. and served as

Executive Vice President, International since 2010. He was previously employed by ConocoPhillips and served as President, ConocoPhillips Canada from

2009 to 2010 and Senior Vice President, Oil Sands and Canadian Arctic from 2007 to 2009.

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

and Strategy since 2010. He was previously employed by Exxon Mobil Corporation and served as Vice President, Worldwide Deepwater and Africa Projects

since 2009; Vice President, Worldwide Deepwater Projects from 2008 to 2009; and Vice President, Established Areas Projects from 2006 to 2008.

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

Ryan M. Lance was appointed Chairman of the Board of Directors and Chief Executive Officer in May 2012, having previously served as Senior Vice

President, Exploration and Production—International since May 2009. Prior to that, he served as President, Exploration and Production—Asia, Africa,

Middle East and Russia/Caspian since April 2009; and President, Exploration and Production— Europe, Asia, Africa and the Middle East from 2007 to

2009.

Glenda M. Schwarz was appointed Vice President and Controller in 2009. She previously served as General Auditor and Chief Ethics Officer from 2008 to

2009.

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Jeff W. Sheets was appointed Executive Vice President, Finance and Chief Financial Officer in May 2012. Prior to that, he served as Senior Vice President,

Finance and Chief Financial Officer since 2010 and Senior Vice President, Planning and Strategy since 2008.

Don E. Wallette, Jr. was appointed Executive Vice President, Commercial, Business Development and Corporate Planning in May 2012. Prior to that, he

served as President, Asia Pacific since 2010 and President, Russia/Caspian from 2006 to 2010.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES

OF EQUITY SECURITIES

Quarterly Common Stock Prices and Cash Dividends Per Share

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

 Stock Price 

 High Low Dividends

2012 

First $ 78.29 68.00 0.66 

Second 77.31 50.62 0.66 

Third 58.90 52.84 0.66 

Fourth 59.65 53.95 0.66 

2011 

First $ 81.80 66.50 0.66 

Second 81.75  70.08 0.66 

Third 80.13 60.40 0.66 

Fourth 73.90 58.65 0.66 

Closing Stock Price at December 31, 2012 $ 57.99 

Closing Stock Price at January 31, 2013 $ 58.00 

Number of Stockholders of Record at January 31, 2013* 56,511 

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

Issuer Purchases of Equity Securities

 Millions of Dollars

Period 

Total Number of

Shares Purchased* 

Average

Price Paid

Per Share 

Shares Purchased

as Part of Publicly

Announced Plans

or Programs** 

Approximate Dollar

Value of Shares

that May Yet Be

Purchased Under the

Plans or Programs

October 1-31, 2012 5,165 $ 57.39 - $ 4,901 

November 1-30, 2012 - - - 4,901 

December 1-31, 2012 7,359 57.67 - 4,901 

Total 12,524 $ 57.56 - 

 *Includes the repurchase of common stock from company employees in connection with the Company’s broad-based employee incentive plans.

**On December 2, 2011, we announced a share repurchase program to repurchase up to $10 billion of common stock over the next two years. Acquisitions for the share repurchase

program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any

time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

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Item 6. SELECTED FINANCIAL DATA

 Millions of Dollars Except Per Share Amounts

 2012 2011 2010 2009 2008

Sales and other operating revenues $ 57,967 64,196 56,215 47,879 87,468 

Income (loss) from continuing operations 7,481 7,188 10,305 3,737 (19,483) 

Per common share 

Basic 5.95 5.18 6.93 2.46 (12.83) 

Diluted 5.91 5.14 6.88 2.44 (12.83) 

Net income (loss) 8,498 12,502 11,417 4,492 (16,279) 

Net income (loss) attributable to ConocoPhillips 8,428 12,436 11,358 4,414 (16,349) 

Per common share 

Basic 6.77 9.04 7.68 2.96 (10.73) 

Diluted 6.72 8.97 7.62 2.94 (10.73) 

Total assets 117,144 153,230 156,314 152,138 142,865 

Long-term debt 20,770 21,610 22,656 26,925 27,085 

Joint venture acquisition obligation—long-term 2,810 3,582 4,314 5,009 5,669 

Cash dividends declared per common share 2.64 2.64 2.15 1.91 1.88 

Many factors can impact the comparability of this information, such as:

• Net income (loss) and Net income (loss) attributable to ConocoPhillips for all periods presented includes income from discontinued operations as a

result of the separation of the Downstream business and our intention to sell our interest in Kashagan and our Nigerian and Algerian businesses.

Income from discontinued operations for these operations was $1,017 million in 2012, $5,314 million in 2011, $1,112 million in 2010, $755

million in 2009 and $3,204 million in 2008. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated

Financial Statements.

• The financial data for 2010 includes the impact of $5,563 million before-tax ($4,463 million after-tax) related to gains from asset dispositions

and LUKOIL share sales.

• The financial data for 2008 includes the impact of impairments related to goodwill and to our LUKOIL investment that together amount to

$32,939 million before- and after-tax.

See Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Notes to Consolidated Financial Statements for a

discussion of factors that will enhance an understanding of this data.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

February 19, 2013

Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future

performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in

this report. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives,

expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words

“anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,”

“would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify

forward-looking statements. The Company does not undertake to update, revise or correct any of the forward-looking information unless required to

do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s

disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE

SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 67.

Due to the separation of the downstream businesses and our intention to sell our interest in the North Caspian Sea Production Sharing Agreement

(Kashagan) and our Nigerian and Algerian businesses in 2012, which are reported as discontinued operations, income (loss) from continuing

operations is more representative of ConocoPhillips as an independent exploration and production company. The terms “earnings” and “loss” as

used in Management’s Discussion and Analysis refer to income (loss) from continuing operations.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural

gas. Headquartered in Houston, Texas, we have operations and activities in 30 countries. At December 31, 2012, we had approximately 16,900 employees

worldwide and total assets of $117 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Discontinued Operations

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining,

marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology

operations included in our Emerging Businesses segment (collectively, our “Downstream business”), were transferred to Phillips 66. As a part of our strategic

asset disposition program, in the fourth quarter of 2012, we agreed to sell our interest in Kashagan and our Nigerian and Algerian businesses. Results of

operations related to Phillips 66, Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Annual Report

on Form 10-K. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Overview

As an independent E&P company, we are solely focused on our core business of exploring for, developing and producing crude oil and natural gas globally.

Our portfolio primarily includes legacy assets in North America, Europe, Asia and Australia; growing North American shale and oil sands businesses;

several major international developments; and a global exploration program. Our value proposition to our shareholders is to deliver

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production and cash margin growth, competitive returns on capital, and a compelling dividend, while keeping our fundamental commitment to safety,

operating excellence and environmental stewardship. We expect to achieve our value proposition through portfolio optimization, investments in high-margin

developments, applying technical capability and maintaining financial flexibility.

In our first year as an independent E&P company, we achieved production of 1.58 million barrels of oil equivalent per day (BOED), including production

from discontinued operations of .05 million BOED; advanced our growth and drilling programs; paid dividends on our common stock of $3.3 billion for the

full year; and repurchased 80 million shares of our common stock at a total cost of $5.1 billion. In 2012, we also announced plans to raise $8–$10 billion of

proceeds from asset dispositions by the end of 2013. As part of this program, we have generated $2.1 billion in proceeds from asset dispositions through

December 31, 2012. We have also announced asset sales, expected to close by mid-2013, which will generate approximately $9.6 billion in additional

proceeds. In the near-term, we will fund a portion of our capital program with these proceeds. Over the next five years, our investment in high-margin

developments should position us to deliver 3–5 percent annual production volume and margin growth, enabling us to fund our capital program organically.

Our total capital program is expected to be $15.8 billion in 2013, compared to $15.7 billion in 2012. Excluding Kashagan, Nigeria and Algeria, which are

reported as discontinued operations, our 2013 capital program is expected to be $15.5 billion, compared to $14.9 billion in 2012. Our investments will be

directed predominantly toward high-quality developments already underway in the United States, Canada, the United Kingdom and Norwegian North Sea,

Malaysia and Australia, as well as exploration opportunities which will build our inventory for the future.

Key Operating and Financial Highlights

Significant highlights during 2012 included the following:

• Completed the separation of our Downstream business on April 30, 2012, creating two independent energy companies, ConocoPhillips and Phillips 66.

• Achieved annual production of 1.58 million BOED, including production from discontinued operations of .05 million BOED, and generated earnings

of $7.5 billion.

• Achieved annual organic reserve replacement of 156 percent and year-end proved reserves of 8.6 billion barrels of oil equivalent.

• Repurchased 80 million ConocoPhillips shares, representing 6 percent of our outstanding shares.

• Paid quarterly dividends of 66 cents per share, consistent with pre-separation dividends.

• Exceeded 100,000 BOED production milestone in the Eagle Ford; continued Bakken activity ramp up.

• Exceeded 100,000 BOED average production in the Canadian Oil sands in the fourth quarter of 2012.

• Progressed FCCL expansion with sanction of Christina Lake Phase F and Narrows Lake Phase A.

• Achieved first oil from the Gumusut Field in Malaysia.

• Increased deepwater Gulf of Mexico position to 1.7 million acres; continued appraisal drilling. Expect to increase acreage position to 2.0 million acres in

the first quarter of 2013.

• Increased Niobrara acreage position to approximately 130,000 acres; continued drilling and testing of unconventional shale plays.

• Progressed the Australia Pacific LNG Project with sanction of the second train in early July 2012; secured $8.5 billion project finance facility.

• Advanced the disposition program with the announcement of agreements to sell Kashagan, Algeria and Nigeria, generating approximately $8.5 billion in

expected proceeds.

Business Environment

In recent years, the business environment for the energy industry has experienced many challenges which have influenced our operations and profitability,

largely due to factors beyond our control, such as the recent financial crisis, geopolitical events or fears thereof, environmental laws, tax regulations,

governmental policies, and weather-related disruptions. These factors generally influence the supply and demand of crude oil and natural gas. The most

significant factor impacting our profitability and related reinvestment of our

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operating cash flows into our business is commodity prices. The prices for commodity products are supply- and demand-based and can be very volatile;

therefore, to navigate through the volatility, our strategy is to maintain a core portfolio of low-risk, high-return development programs associated with legacy

assets, coupled with a portfolio of development opportunities which offer high-margin growth, such as unconventional plays, deepwater and arctic drilling,

and liquefied natural gas (LNG).

Operating and Financial Priorities

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

• Operating safely, consistently and in an environmentally sound manner. Safety is our first priority, and we are committed to protecting the health

and safety of everyone who has a role in our operations and the communities in which we operate. We strive to conduct our business with respect and

care for both the local and global environment and systematically manage risk to drive sustainable business growth.

There has been heightened public focus on the safety of the oil and gas industry as a result of the 2010 Deepwater Horizon incident in the Gulf of

Mexico. Safety and environmental stewardship, including the operating integrity of our assets, remain our highest priorities. In 2010, we formed a

non-profit organization, the Marine Well Containment Company LLC (MWCC), with Exxon Mobil Corporation, Chevron Corporation and Royal

Dutch Shell plc, to develop a new oil spill containment system and improve industry spill response in the U.S. Gulf of Mexico. To complement this

work internationally, in 2011, we and several leading oil and gas companies established the Subsea Well Response Project in Norway, and we

participated in the Oil Spill Prevention and Response Advisory Group in the United Kingdom.

• Adding to our proved reserve base. We primarily add to our proved reserve base in three ways:

o Successful exploration, exploitation and development of new and existing fields.

o Application of new technologies and processes to improve recovery from existing fields.

o Acquisition of existing fields.

Through a combination of the methods listed above, we have been successful in the past in maintaining or adding to our production and proved

reserve base, and we anticipate being able to do so in the future. In the five years ended December 31, 2012, our organic reserve replacement was

108 percent, excluding LUKOIL and the impact of sales and purchases.

Access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in

other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of

access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the

timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.

• Disciplined investment approach. We participate in a capital-intensive industry. As a result, we must often invest significant capital dollars to

explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, or construct pipelines and LNG facilities. We use a

disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on

higher-margin liquids plays and limited investment in North American conventional natural gas. As investments bring more liquids production

online, we expect a corresponding shift in our production mix. However, there are often long lead times from the time we make an investment to the

time the investment is operational and begins generating financial returns.

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Our $15.8 billion capital program includes contributions to FCCL of $0.8 billion. Our capital expenditures and investment budget for 2013,

excluding FCCL, is $15.0 billion, compared to actual capital expenditures and investments in 2012 of $15.0 billion. Excluding discontinued

operations for Kashagan, Nigeria and Algeria, we estimate 2013 capital expenditures and investments will be $14.7 billion, compared to $14.2

billion in 2012. Approximately 10 percent of the 2013 capital budget is expected to be directed toward maintenance of our legacy base portfolio; 40

percent is expected to be allocated to exploitation programs in our legacy asset base, which is intended to offset natural decline from these assets; 35

percent is expected to be spent on sanctioned major developments, such as Eldfisk II, Jasmine and APLNG; and 15 percent is planned for our

worldwide exploration and appraisal program, which will target both conventional and unconventional plays.

• Portfolio optimization. We continue to optimize our asset portfolio by focusing on assets which offer the highest returns and growth potential, while

selling nonstrategic holdings. In 2012, we announced plans to sell an additional $8–$10 billion of noncore assets through the end of 2013. During

2012, we sold our Vietnam business, the Statfjord and Alba fields in the North Sea, our investment in Naryanmarneftegaz (NMNG) in Russia, and

we further diluted our interest in APLNG from 42.5 percent to 37.5 percent. We recently announced our intention to sell our 8.4 percent interest in

Kashagan, our Algerian and Nigerian businesses, and certain properties in the Cedar Creek Anticline, located in North Dakota and Montana. Cedar

Creek Anticline is expected to close in the first quarter of 2013, and the remaining transactions are expected to close by mid-2013, subject to

customary governmental approvals. Additionally, in January 2013, we sold our 24.5 percent interest in the N Block, located offshore Kazakhstan.

In 2011, we sold certain noncore assets in the Lower 48 and western Canada, and we completed the divestiture of our entire interest in LUKOIL.

• Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs,

within the context of our commitment to safety and environmental stewardship, is a high priority. We monitor these costs using various

methodologies that are reported to senior management monthly, on both an absolute-dollar basis and a per-unit basis. Because managing operating

and overhead costs is critical to maintaining competitive positions in our industry, cost control is a component of our variable compensation

programs. Operating and overhead costs increased 8 percent in 2012 compared with 2011, primarily as a result of major turnaround expenses in

Australia, higher operating expenses in the Lower 48 associated with improved production as a result of increased drilling programs, the settlement of

environmental claims and other costs related to Bohai Bay, China, and costs associated with the separation of Phillips 66.

• Developing and retaining a talented work force. We strive to attract, train, develop and retain individuals with the knowledge and skills to

implement our business strategy and who support our values and ethics. Throughout the company, we focus on the continued learning, development

and technical training of our employees. Professional new hires participate in structured development programs designed to accelerate their technical

and functional skills.

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Other significant factors that can affect our profitability include:

• Commodity prices. Our earnings generally correlate with industry price levels for crude oil and natural gas. These are commodity products, the prices

of which are subject to factors external to our company and over which we have no control. The following table depicts the average benchmark prices for

West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:

 Dollars Per Unit

 2012 2011 2010

Market Indicators 

WTI (per barrel) $ 94.16 95.05 79.39

Dated Brent (per barrel) 111.58  111.27  79.47

U.S. Henry Hub first of month (per million British thermal units) 2.79 4.04 4.39

Global oil prices remained relatively flat in 2012, compared to 2011. In 2012, global oil demand grew at approximately the same pace as in 2011, at

about 0.9 percent or 800 thousand barrels per day, as the pace of economic expansion moderated due to intentional slowing in China, coupled with fiscal

uncertainties in the European Union and the United States. Global oil production rose due to an increase in the Organization of Petroleum Exporting

Countries (OPEC) and North American production. WTI continued to trade at a discount to Brent throughout 2011 and 2012, mainly due to high

inventory levels and excess crude supply in the U.S. Midcontinent market, largely as a result of limited pipeline capacity.

Henry Hub natural gas prices decreased 31 percent in 2012, compared with 2011. U.S. natural gas prices were depressed in 2012, mainly due to high

inventory levels, a warmer-than-normal winter and sustained production from shale plays. We expect these factors will continue to moderate natural gas

prices in the near- to mid-term. The expansion in shale production has also helped boost supplies of natural gas liquids, resulting in downward pressure

on natural gas liquids prices in the United States. As a result, our domestic realized natural gas liquids price declined 30 percent in 2012 compared with

2011. Our realized bitumen price declined 14 percent in 2012. We expect bitumen prices to remain weak in the near-term, until additional heavy refining

capacity comes on-line.

In recent years, the use of hydraulic fracturing in shale natural gas formations has led to increased industry actual and forecasted natural gas production

in the United States. Although providing short- and long-term significant growth opportunities for our company, the increased abundance of natural gas

due to development of shale plays could also have adverse financial implications to us, including: an extended period of low natural gas and natural gas

liquids prices; production curtailments on properties that produce primarily natural gas; continued delay of plans to develop Alaska North Slope

natural gas fields; and underutilization of LNG regasification facilities. Should one or more of these events occur, our revenues would be reduced and

additional impairments might be possible.

• Impairments. As mentioned above, we participate in capital-intensive industries. At times, our properties, plants and equipment and investments

become impaired when, for example, our reserve estimates are revised downward, commodity prices decline significantly for long periods of time, or a

decision to dispose of an asset leads to a write-down to its fair value. We may also invest large amounts of money in exploration which, if exploratory

drilling proves unsuccessful, could lead to a material impairment of leasehold values. Before-tax impairments in 2012 totaled $1.2 billion and primarily

resulted from the impairments of the Mackenzie Gas Project and associated leaseholds in Canada; Cedar Creek Anticline in the Lower 48; various

properties in Europe, which have ceased production or are nearing the end of their useful lives; and the N Block in the Caspian Sea. Before-tax

impairments in 2011 totaled $0.8 billion and primarily resulted from the impairments of our equity

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investment in NMNG and certain Canadian natural gas properties. For additional information, see Note 9—Impairments, in the Notes to Consolidated

Financial Statements.

• Effective tax rate. Our operations are located in countries with different tax rates and fiscal structures. Accordingly, even in a stable commodity price

and fiscal/regulatory environment, our overall effective tax rate can vary significantly between periods based on the “mix” of pretax earnings within our

global operations.

• Fiscal and regulatory environment. Our operations can be affected by changing economic, regulatory and political environments in the various

countries in which we operate, including the United States. Civil unrest or strained relationships with governments may impact our operations or

investments. These changing environments have generally negatively impacted our results of operations, and further changes to government fiscal take

could have a negative impact on future operations. Our production operations in Libya and related oil exports were temporarily suspended in 2011

during Libya’s period of civil unrest. Our assets in Venezuela and Ecuador were expropriated in 2007 and 2009, respectively. In Canada, the Alberta

provincial government changed the royalty structure in 2009 to tie a component of the new rate to prevailing prices. Our management carefully considers

these events when evaluating projects or determining the level of activity in such countries.

Outlook

Total production for the first quarter of 2013 is expected to be 1.58 million to 1.6 million BOED, including production from discontinued operations of

approximately 40,000 BOED. Full-year 2013 production from continuing operations is expected to be 1.475 million to 1.525 million BOED,which is

consistent with 2012 production from continuing operations adjusted for dispositions.

Segment Analysis

We manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe,

Asia Pacific and Middle East, and Other International.

The LUKOIL Investment segment represents our prior investment in the ordinary shares of OAO LUKOIL, which was sold in the first quarter of 2011.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, costs related to the

separation of Phillips 66 and certain technology activities, as well as licensing revenues received.

Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our

continuing operations, including commodity prices and production.

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RESULTS OF OPERATIONS

Consolidated Results

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

 Millions of Dollars

Years Ended December 31 2012 2011 2010 

Alaska $ 2,276 1,984 1,727 

Lower 48 and Latin America 1,029 1,288 1,029 

Canada (684) 91 2,902 

Europe 1,498 1,830 1,703 

Asia Pacific and Middle East 3,996 3,093 2,153 

Other International 359 (377) (417) 

LUKOIL Investment - 239 2,513 

Corporate and Other (993) (960) (1,305) 

Income from continuing operations $ 7,481 7,188 10,305 

2012 vs. 2011

Earnings for ConocoPhillips increased 4 percent in 2012. The increase was mainly due to:

• Higher gains from asset sales. In 2012, gains from asset dispositions were $1,567 million after-tax, compared with gains in 2011 from asset

dispositions and LUKOIL share sales of $141 million after-tax.

• Higher LNG and crude oil prices.

• Lower production taxes, mainly as a result of lower volumes.

• The benefit from the realization of a tax loss carryforward of $236 million.

• The favorable resolution of pending claims and settlements of $235 million after-tax.

These items were partially offset by:

• Lower volumes, largely due to dispositions and reduced production in China.

• Lower natural gas, natural gas liquids and bitumen prices.

• Higher operating and selling, general and administrative (SG&A) expenses, which included pension settlement expenses of $87 million after-tax and

separation costs of $84 million after-tax.

• Higher impairments. Non-cash impairments in 2012 totaled $900 million after-tax, compared with impairments in 2011 of $698 million after-tax.

2011 vs. 2010

Earnings for ConocoPhillips decreased 30 percent in 2011. The decrease was mainly due to:

• Lower gains from asset sales. In 2011, gains from asset dispositions and LUKOIL share sales were $141 million after-tax, compared with gains in

2010 of $4,463 million after-tax.

• The absence of equity earnings from LUKOIL due to the divestiture of our interest.

• Lower production volumes.

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These items were partially offset by:

• Higher commodity prices. Commodity price benefits were partly offset by increased production taxes.

• Lower depreciation, depletion and amortization (DD&A) expenses, mainly as a result of lower volumes.

Income Statement Analysis

2012 vs. 2011

Sales and other operating revenues decreased 10 percent in 2012, mainly due to lower natural gas and natural gas liquids prices, partly offset by higher LNG

prices.

Equity in earnings of affiliates increased 54 percent in 2012. The increase primarily resulted from:

• Improved earnings from Qatar Liquefied Gas Company Limited (3) (QG3), mainly due to higher LNG prices, partly offset by lower volumes.

• Lower impairments from NMNG. In 2011, equity earnings included a $395 million impairment of our equity investment.

Gain on dispositions increased $1,287 million in 2012. Gains in 2012 primarily resulted from the disposition of our Vietnam business, our equity investment

in NMNG, the Statfjord and Alba fields in the North Sea and our interest in Block 39 in Peru, partly offset by the loss on further dilution of our equity

interest in APLNG from 42.5 percent to 37.5 percent. Gains in 2011 mainly consisted of the divestiture of our remaining LUKOIL shares and the disposition

of certain properties located in the Lower 48 and Canada, partially offset by the loss on the initial dilution of our equity interest in APLNG from 50 percent to

42.5 percent. For additional information, see Note 5—Assets Held for Sale or Sold and Note 6—Investments, Loans and Long-Term Receivables, in the

Notes to Consolidated Financial Statements.

Other income increased 78 percent in 2012, mostly as a result of the favorable resolution of the Petróleos de Venezuela S.A. (PDVSA) International Chamber of

Commerce (ICC) arbitration. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Purchased commodities decreased 15 percent in 2012, largely as a result of lower U.S. natural gas prices, partly offset by higher purchased volumes.

Production and operating expenses increased 6 percent in 2012, mostly due to major turnaround expenses at our Bayu-Undan Field and Darwin LNG facility

and higher operating expenses in the Lower 48.

SG&A expenses increased 28 percent in 2012, primarily due to pension settlement expense and costs associated with the separation of Phillips 66.

Exploration expenses increased 45 percent in 2012, mostly due to the impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as

a result of its indefinite suspension in the first quarter of 2012.

Impairments increased 112 percent in 2012. Impairments in 2012 included the $213 million impairment of capitalized development costs associated with the

Mackenzie Gas Project in the first quarter of 2012, the $192 million property impairment related to the disposition of Cedar Creek Anticline, as well as

increases in the asset retirement obligation for various properties mostly located in the United Kingdom, which have ceased production or are nearing the end

of their useful lives. Impairments in 2011 consisted of various North American natural gas properties. For additional information, see Note 9—Impairments,

in the Notes to Consolidated Financial Statements.

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Taxes other than income taxes decreased 11 percent in 2012, mostly due to lower production taxes as a result of lower crude oil production volumes.

Interest and debt expense decreased 26 percent in 2012, primarily due to higher capitalized interest on projects and lower interest expense due to lower average

debt levels.

See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

2011 vs. 2010

Sales and other operating revenues increased 14 percent in 2011, mainly due to significantly higher prices for crude oil and higher LNG prices and volumes.

Lower crude oil and natural gas volumes partly offset this increase.

Equity in earnings of affiliates decreased 10 percent in 2011. The decrease primarily resulted from the absence of equity earnings from LUKOIL due to the

divestiture of our interest. This decrease was partially offset by:

• Earnings from QG3, primarily due to sales of LNG following production startup, which occurred in October 2010.

• Lower impairments from NMNG. In 2011, equity earnings included a $395 million impairment of our equity investment, and 2010 equity earnings

included a $645 million impairment.

• Improved earnings from FCCL Partnership, mostly due to higher commodity prices and volumes.

Gain on dispositions decreased 93 percent in 2011. Gains in 2011 primarily resulted from the disposition of certain assets located in the Lower 48 and

Canada, as well as the divestiture of our remaining LUKOIL shares. These gains were partially offset by the loss on dilution of our equity interest in APLNG

from 50 percent to 42.5 percent. Gains in 2010 primarily reflected the $2,878 million gain realized from the sale of our interest in Syncrude, the $1,749

million gain on the divestiture of a portion of our LUKOIL shares, and gains on the disposition of certain assets located in the Lower 48 and Canada.

Purchased commodities increased 20 percent in 2011, mainly due to higher natural gas prices in Europe.

DD&A decreased 15 percent in 2011. The decrease was mostly associated with lower production volumes and lower unit-of-production rates related to reserve

bookings in 2011.

Impairments increased $240 million in 2011, mostly due to the impairment of various North American natural gas properties in 2011.

Taxes other than income taxes increased 43 percent in 2011, mostly due to higher production taxes in Alaska as a result of higher crude oil prices.

Interest and debt expense decreased 18 percent in 2011, primarily due to lower average debt levels.

See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

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Summary Operating Statistics

 2012 2011 2010

 

Average Net Production 

Crude oil (MBD) 595 622 733

Natural gas liquids (MBD) 156 145 147

Synthetic oil (MBD) - - 12

Bitumen (MBD) 93 67 5 9

Natural gas (MMCFD) 4,096 4,359 4,465

Total Production (MBOED) 1,527 1,561 1,695

 Dollars Per Unit

Average Sales Prices 

Crude oil (per barrel) $ 105.72 105.52 77.74

Natural gas liquids (per barrel) 46.36 55.73 46.00

Synthetic oil (per barrel) - - 77.56

Bitumen (per barrel) 53.91 62.56 53.06

Natural gas (per thousand cubic feet) 5.48 5.80 5.05

 Millions of Dollars

Worldwide Exploration Expenses 

General and administrative; geological and geophysical; and lease rentals $ 626 569 649

Leasehold impairment 719 159 241

Dry holes 155 310 235

 $ 1,500 

 1,038  1,125

Excludes discontinued operations.

(1)Excludes amounts related to LUKOIL.

(2)Thousands of barrels per day.

(3)Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

(4)Thousands of barrels of oil equivalent per day.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2012,

our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea,

Indonesia, China, Malaysia, Qatar, Libya and Russia.

In 2012, average production from continuing operations decreased 2 percent compared with 2011, primarily as a result of normal field decline, the impact

from asset dispositions and higher planned and unplanned downtime. These decreases were largely offset by additional production from major developments,

mainly from shale plays in the Lower 48 and ramp-up of new phases at FCCL, the resumption of production in Libya following a period of civil unrest in

2011, and increased drilling programs in the Lower 48.

In 2011, average production decreased 8 percent compared with 2010, mostly as a result of suspended operations in Libya and Bohai Bay, China, asset

dispositions and higher unplanned downtime. Normal field decline was largely offset by new production.

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(2)

(3)

(4)
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Alaska

 2012 2011 2010

Income from Continuing Operations (millions of dollars) $ 2,276 1,984 1,727

Average Net Production 

Crude oil (MBD) 188 200 215

Natural gas liquids (MBD) 16 15 15

Natural gas (MMCFD) 55 61 82

Total Production (MBOED) 213 225 244

Average Sales Prices 

Crude oil (per barrel) $ 109.62  105.95  78.65

Natural gas (per thousand cubic feet) 4.22 4.56 4.62

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. In 2012, Alaska

contributed 24 percent of our worldwide liquids production and 1 percent of our natural gas production.

2012 vs. 2011

Our Alaska operations reported earnings of $2,276 million in 2012, a 15 percent increase compared with earnings of $1,984 million in 2011. The increase in

earnings was primarily due to higher crude oil prices, lower production taxes as a result of lower crude oil production volumes, the absence of the $54 million

after-tax write-off of our investment associated with the cancellation of the Denali gas pipeline project in 2011, and lower DD&A. These increases were partly

offset by lower crude oil sales volumes and higher operating expenses.

Production averaged 213 MBOED in 2012, a decrease of 5 percent compared with 2011. This decrease was mainly due to normal field decline, partially offset

by lower unplanned downtime.

2011 vs. 2010

Alaska earnings were $1,984 million in 2011, a 15 percent increase compared with earnings of $1,727 million in 2010. Earnings in 2011 benefitted from

significantly higher crude oil prices, partially offset by higher production taxes, lower volumes, higher operating expenses, and the $54 million after-tax writeoff of the Denali gas pipeline project.

Production averaged 225 MBOED in 2011, a decrease of 8 percent compared with 2010. This decrease was mainly due to normal field decline, somewhat

offset by increased drilling activity.

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Lower 48 and Latin America

 2012 2011 2010

Income from Continuing Operations (millions of dollars) $ 1,029 1,288 1,029

Average Net Production 

Crude oil (MBD) 123 94 85

Natural gas liquids (MBD) 85 74 75

Natural gas (MMCFD) 1,493  1,556  1,695

Total Production (MBOED) 457 428 442

Average Sales Prices 

Crude oil (per barrel) $ 91.67 92.79 73.52

Natural gas liquids (per barrel) 35.45 50.55 39.92

Natural gas (per thousand cubic feet) 2.67 3.99 4.25

During 2012, Lower 48 and Latin America contributed 25 percent of our worldwide liquids production and 37 percent of our natural gas production. The

Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states.

2012 vs. 2011

Lower 48 and Latin America operations reported earnings of $1,029 million in 2012, a 20 percent decrease compared with 2011. The decrease in earnings was

primarily the result of substantially lower natural gas and natural gas liquids prices; higher DD&A, mostly due to higher crude oil and natural gas liquids

production; lower gains from asset dispositions; higher operating expenses and higher impairments. These decreases were partially offset by higher crude oil

and natural gas liquids volumes. Earnings in 2012 also benefitted from the realization of a tax loss carryforward of $236 million, and the favorable resolution

of the PDVSA ICC arbitration.

In November 2012, based on an ICC arbitration tribunal ruling, PDVSA paid ConocoPhillips $68 million for pre-expropriation breaches of the Petrozuata

project agreements, which resulted in a $61 million after-tax earnings increase. The Company also recognized additional income of $173 million after-tax

associated with the reversal of a related contingent liability accrual. These amounts included interest of $33 million after-tax, which has been reflected in the

Corporate and Other segment. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Average production in the Lower 48 increased 7 percent in 2012, while average liquids production increased 24 percent over the same period. New production,

primarily from the Eagle Ford, Bakken and Permian areas, and improved drilling and well performance more than offset normal field decline. In addition,

higher unplanned downtime during 2012 partly offset the increase in production.

2011 vs. 2010

Lower 48 and Latin America earnings were $1,288 million in 2011, a 25 percent increase compared with 2010. The increase in 2011 earnings was mainly

due to higher crude oil and natural gas liquids prices and lower DD&A. These increases were partly offset by lower gains from asset sales, lower natural gas

prices, higher dry hole expenses and impairments.

Production averaged 428 MBOED in 2011, a 3 percent decrease compared with 2010. The decrease in 2011 was mainly due to asset dispositions. Normal

field decline was offset by new production, mainly from the Eagle Ford, Bakken, Permian and Barnett areas, and improved drilling and well performance.

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Canada

 2012 2011 2010

Income (Loss) from Continuing Operations (millions of dollars) $ (684) 91 2,902

Average Net Production 

Crude oil (MBD) 13 12 15

Natural gas liquids (MBD) 24 26 23

Synthetic oil (MBD) - - 12

Bitumen (MBD) 

Consolidated operations 12 10 10

Equity affiliates 81 57 49

Total bitumen 93 67 5 9

Natural gas (MMCFD) 857 928 984

Total Production (MBOED) 273 260 273

Average Sales Prices 

Crude oil (per barrel) $ 78.26 86.04  67.99

Natural gas liquids (per barrel) 48.64 56.84 47.68

Synthetic oil (per barrel) - - 77.56

Bitumen (dollars per barrel) 

Consolidated operations 57.58 55.16 51.10

Equity affiliates 53.39 63.93 53.43

Total bitumen 53.91 62.56 53.06

Natural gas (per thousand cubic feet) 2.13 3.46 3.74

Our Canadian operations are mainly comprised of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern

Alberta. In 2012, Canada contributed 15 percent of our worldwide liquids production and 21 percent of our natural gas production.

2012 vs. 2011

Canada operations reported a loss of $684 million in 2012, a reduction of $775 million compared with earnings of $91 million in 2011. The decrease in

earnings was largely due to significantly lower natural gas prices, lower bitumen prices and higher impairments, mainly as a result of the $520 million aftertax impairment of the Mackenzie Gas Project and associated leaseholds in 2012. These decreases were partially offset by significantly higher bitumen volumes

from FCCL and lower DD&A from our western Canadian gas assets, primarily due to asset dispositions and curtailments. Equity earnings from FCCL were

also impacted by higher operating and DD&A expenses, mostly as a result of higher production volumes.

Average production in Canada increased 5 percent in 2012, while average liquids production increased 24 percent over the same period. Normal field decline

and the impact from asset dispositions were more than offset by new production from Christina Lake Phases C and D and improved well performance from

Foster Creek, both in FCCL.

2011 vs. 2010

Canada earnings were $91 million in 2011, a reduction of $2,811 million compared with 2010. This decrease was primarily due to lower gains from asset

dispositions. Earnings in 2010 included the $2,679 million after-tax gain realized from the sale of our 9.03 percent interest in the Syncrude oil sands mining

operation. Lower volumes, mostly as a result of asset dispositions, impairments on various natural gas properties and lower

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natural gas prices also contributed to the decrease in 2011 earnings. These decreases were somewhat offset by higher bitumen, natural gas liquids and crude

oil prices, lower DD&A and lower dry hole expenses.

Production averaged 260 MBOED in 2011, a 5 percent decrease compared with 2010. The decrease was mainly due to asset dispositions and normal field

decline, partly offset by new production from FCCL.

Europe

 2012 2011 2010

Income from Continuing Operations (millions of dollars) $ 1,498 1,830 1,703

Average Net Production 

Crude oil (MBD) 135 164 196

Natural gas liquids (MBD) 7 11 15

Natural gas (MMCFD) 516 626 815

Total Production (MBOED) 228 279 347

Average Sales Prices 

Crude oil (dollars per barrel) $ 113.08  111.82  79.74

Natural gas liquids (per barrel) 61.53 59.19 46.75

Natural gas (per thousand cubic feet) 9.76 9.26 6.94

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland

and Greenland. In 2012, our Europe operations contributed 17 percent of our worldwide liquids production and 13 percent of our natural gas production.

2012 vs. 2011

Europe operations reported earnings of $1,498 million in 2012, an 18 percent decrease compared with 2011. The reduction in earnings was mainly due to

lower volumes and higher impairments. Earnings for 2012 were also impacted by additional income tax expense due to legislation enacted in the United

Kingdom in 2012, which restricted corporate tax relief on decommissioning costs. The additional tax expense resulted from the revaluation of deferred tax

balances. These decreases to earnings were partly offset by a $287 million after-tax gain on sale of our interests in the Statfjord and Alba fields and lower

DD&A. Additionally, earnings in 2011 included a $316 million increase in U.K. corporate income tax expense due to legislation enacted in 2011. This

additional tax expense consisted of $106 million for the revaluation of deferred tax liabilities and $210 million to reflect the higher tax rates from the effective

date of the legislation, March 24, 2011, through December 31, 2011.

Production averaged 228 MBOED in 2012, an 18 percent decrease compared with 2011. The decrease was mostly due to normal field decline, dispositions

and higher unplanned downtime in the United Kingdom.

2011 vs. 2010

Earnings for our Europe operations were $1,830 million in 2011, a 7 percent increase compared with earnings of $1,703 million in 2010. Earnings benefitted

from significantly higher prices and lower DD&A, partly offset by lower volumes and the $316 million increase in U.K. corporate income tax expense.

Earnings in 2010 also benefitted from a $58 million insurance settlement.

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Production averaged 279 MBOED in 2011, a 20 percent decrease compared with 2010. The decrease mainly resulted from normal field decline, unplanned

downtime and dispositions, somewhat offset by new production from Britannia and J-Block.

Asia Pacific and Middle East

 2012 2011 2010 

Income from Continuing Operations (millions of dollars) $ 3,996 3,093 2,153 

Average Net Production 

Crude oil (MBD) 

Consolidated operations 68 9 9 122 

Equity affiliates 15 16 2 

Total crude oil 83 115 124 

Natural gas liquids (MBD) 

Consolidated operations 16 12 18 

Equity affiliates 8 7 1 

Total natural gas liquids 24 19 19 

Natural gas (MMCFD) 

Consolidated operations 672 695 712 

Equity affiliates 485 492 169 

Total natural gas 1,157 1,187 881 

Total Production (MBOED) 300 332 290 

Average Sales Prices 

Crude oil (dollars per barrel) 

Consolidated operations $108.20  109.84  77.69 

Equity affiliates 108.07 106.96 89.24 

Total crude oil 108.18 109.46 77.89 

Natural gas liquids (dollars per barrel) 

Consolidated operations 79.26 72.87 60.57 

Equity affiliates 77.30 70.62 65.16 

Total natural gas liquids 78.64 71.98 60.73 

Natural gas (dollars per thousand cubic feet) 

Consolidated operations 10.63 9.82 7.39 

Equity affiliates 8.54 5.93 1.91 

Total natural gas 9.75 8.21 6.35 

The Asia Pacific and Middle East segment has producing operations in China, Indonesia, Malaysia, Australia, the Timor Sea and Qatar, as well as

exploration activities in Bangladesh and Brunei. During 2012, Asia Pacific and Middle East contributed 13 percent of our worldwide liquids production and

28 percent of our natural gas production.

2012 vs. 2011

Asia Pacific and Middle East operations reported earnings of $3,996 million in 2012, a 29 percent increase compared with 2011 earnings of $3,093 million.

Earnings in 2012 primarily benefitted from higher gains from asset dispositions, significantly higher LNG prices, higher equity earnings due to lower DD&A

and operating expenses from QG3, and lower Bohai Bay expenses incurred in 2012. Amounts realized from dispositions in

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2012 consisted of a $931 million after-tax gain on sale of our Vietnam business and a $133 million after-tax loss recognized on the further dilution of our

equity interest in APLNG from 42.5 percent to 37.5 percent. In 2011, we recognized a $279 million after-tax loss on the initial dilution of our interest in

APLNG from 50 percent to 42.5 percent. The increase in 2012 earnings was partly offset by lower crude oil volumes, mainly as a result of the Bohai Bay

seepage incidents and the Vietnam disposition, lower LNG volumes and higher production taxes.

Average production decreased 10 percent in 2012. The decrease was largely due to the disposition of our Vietnam business, normal field decline, planned

maintenance at our Bayu-Undan Field and Darwin LNG Facility in 2012, as well as lower production in China.

2011 vs. 2010

Asia Pacific and Middle East earnings increased 44 percent in 2011, compared with 2010 earnings. The increase was mainly due to higher prices, higher

volumes, mostly as a result of a full year of LNG sales from QG3, and lower DD&A. These increases to earnings were partly offset by higher production

taxes, higher operating expenses and the $279 million loss on dilution of our equity interest in APLNG from 50 percent to 42.5 percent.

Production averaged 332 MBOED in 2011, a 14 percent increase compared with 2010. The increase was largely due to the ramp-up of production from QG3,

partly offset by higher unplanned downtime, mainly in China, and normal field decline.

Timor-Leste Arbitration

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax

assessments. Between 2010 and 2012, ConocoPhillips has paid, under protest, tax assessments totaling approximately $227 million, which are primarily

recorded in the “Investments and long-term receivables” line on our December 31, 2012, consolidated balance sheet. The arbitration will be conducted in

Singapore 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. The arbitration process is currently underway. Future impacts on our business are not known at this time.

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Other International

 2012 2011 2010 

Income (Loss) from Continuing Operations (millions of dollars)* $ 359 (377) (417) 

Average Net Production* 

Crude oil (MBD) 

Consolidated operations 40 8 46 

Equity affiliates 13 29 52 

Total crude oil 53 37 98 

Natural gas (MMCFD) 18 1 8 

Total Production (MBOED) 56 37 99 

Average Sales Prices* 

Crude oil (dollars per barrel) 

Consolidated operations $110.75 98.30 79.22 

Equity affiliates 96.50  101.62 74.33 

Total crude oil 107.56 101.14 76.57 

Natural gas (dollars per thousand cubic feet) 5.55 0.09 0.09 

* Prior periods have been restated to exclude discontinued operations.

The Other International segment includes producing operations in Libya and Russia, as well as exploration activities in Angola and the Caspian Sea. During

2012, Other International contributed 6 percent of our worldwide liquids production.

2012 vs. 2011

Other International operations reported earnings of $359 million in 2012, a $736 million increase compared with 2011. Earnings in 2012 primarily benefitted

from the $443 million after-tax gain on disposition of our interest in NMNG, the absence of a $395 million after-tax impairment of our investment in NMNG

in 2011, and higher earnings from Libya, as a result of the resumption of production following a period of civil unrest in 2011. These increases were partially

offset by a $108 million after-tax impairment associated with the N Block in the Caspian Sea.

Production averaged 56 MBOED in 2012, a 51 percent increase compared with 2011 production. The increase was mainly due to the resumption of

production in Libya, partly offset by field decline in Russia and the disposition of our interest in NMNG.

2011 vs. 2010

Other International reported a loss of $377 million in 2011, compared with a loss of $417 million in 2010. The improvement in 2011 was primarily the result

of higher crude oil prices, higher equity earnings due to lower DD&A from NMNG and lower impairments. In 2011, we recorded a $395 million impairment

of our equity investment in NMNG, compared with a $645 million impairment to NMNG recorded in 2010. These improvements in 2011 were partly offset

by considerably lower volumes, mainly from Libya and Russia, as well as the absence of a deferred tax benefit recognized in 2010.

Production averaged 37 MBOED in 2011, a 63 percent decrease compared with 2010 production. The decrease was mostly due to suspended operations in

Libya following a period of civil unrest in 2011, and field decline in Russia.

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Asset Dispositions

We recently announced our intention to sell our 8.4 percent interest in Kashagan and our Algerian and Nigerian businesses. The transactions are expected to

close by mid-2013, subject to customary governmental approvals. In January 2013, we sold our 24.5 percent interest in the N Block, located offshore

Kazakhstan.

LUKOIL Investment

 Millions of Dollars

 2012 2011 2010 

Income from Continuing Operations $ - 239 2,513 

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in

Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.

2011 vs. 2010

Earnings in 2011 primarily represented the realized gain on remaining share sales. Earnings in 2010 primarily reflected earnings from the equity investment in

LUKOIL we held at the time, in addition to gains on the partial sale of our LUKOIL investment.

Corporate and Other

 Millions of Dollars

 2012 2011 2010 

Income (Loss) from Continuing Operations 

Net interest $ (648) (710) (995) 

Corporate general and administrative expenses (313) (190) (209) 

Technology (4) 15 (23) 

Separation costs (84) (25) - 

Other 56 (50) (78) 

 $ (993) (960) (1,305) 

2012 vs. 2011

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of

debt. Net interest decreased 9 percent in 2012, mostly due to higher capitalized interest, lower interest expense due to lower average debt levels, higher interest

income and the $33 million after-tax interest benefit from the favorable resolution of the PDVSA arbitration. These improvements were partly offset by a $68

million after-tax premium on early debt retirement.

Corporate general and administrative expenses increased 65 percent in 2012, mainly due to $87 million of after-tax pension settlement expense and higher

costs related to compensation and benefit plans.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on heavy oil and oil

sands; unconventional reservoirs; subsurface technology; liquefied natural gas; and arctic, deepwater and sustainability technology. Technology reported a

loss of $4 million in 2012, compared to earnings of $15 million in 2011, primarily as a result of lower licensing revenues.

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Separation costs consist of expenses related to the separation of our Downstream business into a stand-alone, publicly traded company, Phillips 66.

Separation costs increased $59 million in 2012 and mainly included costs related to compensation and benefit plans.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and

other costs not directly associated with an operating segment. The improvement in “Other” in 2012 was largely due to various tax-related adjustments,

including a $39 million after-tax settlement. These improvements were partially offset by higher environmental expenses and foreign currency transaction

losses.

2011 vs. 2010

Net interest decreased 29 percent in 2011, mostly due to lower interest expense, as a result of lower average debt levels. In addition, the absence of a

$114 million after-tax premium on early debt retirement and the absence of $24 million of after-tax interest expense associated with a tax settlement, both of

which occurred in 2010, contributed to the decrease.

Corporate general and administrative expenses decreased 9 percent in 2011, mainly due to lower costs related to compensation and benefit plans, partly offset

by higher advertising expenses.

Technology had earnings of $15 million in 2011, as a result of higher licensing revenues, partially offset by higher project expenses.

Separation costs in 2011 primarily included legal, accounting and information systems costs.

Changes in the “Other” category primarily resulted from lower environmental costs and gains from foreign currency transactions, partially offset by a $20

million after-tax property impairment.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

 

Millions of Dollars

Except as Indicated

 2012 2011 2010

Net cash provided by continuing operating activities $ 13,458 13,953 14,013

Net cash provided by discontinued operations 464 5,693 3,032

Short-term debt 955 1,013 936

Total debt 21,725 22,623 23,592

Total equity 48,427 65,749  69,124

Percent of total debt to capital* 31 % 26 25

Percent of floating-rate debt to total debt** 9 % 10 10

 * Capital includes total debt and total equity.

** Includes effect of interest rate swaps.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from continuing operating activities is the

primary source of funding. In addition, during 2012, we received $2,132 million in proceeds from asset sales and $1,996 million for the issuance of debt.

During 2012, the primary uses of our available cash were $14,172 million to support our ongoing capital expenditures and investments; $5,098 million to

repurchase common stock; $3,278 million to pay dividends on our common stock; and $2,565 million to repay debt. During 2012, cash and cash

equivalents decreased by $2,162 million to $3,618 million.

In addition to cash flows from continuing operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs and

our shelf registration statement to support our short- and long-term liquidity requirements. We believe our current cash balance and cash generated by

operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our

funding requirements in the near and long term, including our capital program, dividend payments, required debt payments and the funding requirements to

FCCL.

Separation of Phillips 66

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66.

Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain

technology operations included in our Emerging Businesses segment, were transferred to Phillips 66. After the close of the New York Stock Exchange on

April 30, 2012, the shareholders of record as of 5:00 p.m. Eastern time on April 16, 2012 (the Record Date), received one share of Phillips 66 common stock

for every two ConocoPhillips common shares held as of the Record Date.

In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution. These funds will be used solely to

pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. At December 31,

2012, the unused amount of the special cash distribution was $748 million and is designated as “Restricted cash” on our consolidated balance sheet.

Significant Sources of Capital

Operating Activities

During 2012, cash provided by continuing operating activities was $13,458 million, a 4 percent decrease from 2011. During 2011, cash provided by

continuing operations was $13,953 million compared with $14,013 million in 2010.

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While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly

dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. Prices and margins in our industry are typically volatile, and are

driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a

corresponding change in our operating cash flows.

The level of our production volumes also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of

fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success,

and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although

generally this variability has not been as significant as that caused by commodity prices.

Our 2012 production from continuing operations averaged 1.527 million BOED. Future production is subject to numerous uncertainties, including, among

others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing

and variable-royalty contracts; timing of startups and major turnarounds; and weather-related disruptions. Our production from continuing operations in 2013

is expected to be 1.475 million to 1.525 million BOED.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our total reserve replacement in 2012 was 142 percent.

Excluding the impact of sales and purchases, the organic reserve replacement was 156 percent of 2012 production. Over the five-year period ended

December 31, 2012, our reserve replacement was 48 percent (including 65 percent from consolidated operations) reflecting the disposition of our interest in

LUKOIL and the impact of our asset disposition program. Excluding these items and purchases, our five-year organic reserve replacement was 108 percent.

The total reserve replacement amount above is based on the sum of our net additions (revisions, improved recovery, purchases, extensions and discoveries,

and sales) divided by our production, as shown in our reserve table disclosures. For additional information about our proved reserves, including both

developed and undeveloped reserves, see the “Oil and Gas Operations” section of this report.

We are pursuing developments we anticipate will allow us to add to our reserve base. However, access to additional resources has become increasingly difficult

as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make development uneconomic or unattractive. In

addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may

negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to

replace our production over subsequent years.

As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are imprecise; therefore, each year reserves may be

revised upward or downward due to the impact of changes in commodity prices or as more technical data becomes available on reservoirs. In 2012, 2011 and

2010, revisions increased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.

Asset Sales

Proceeds from asset sales in 2012 were $2,132 million, primarily from the sale of our Vietnam business, the sale of our equity interest in NMNG and the sale

of our interest in the Statfjord and Alba fields in the North Sea. This compares with proceeds of $2,192 million in 2011, which mainly included the sale of

our remaining interest in LUKOIL and certain properties located in the Lower 48. We have announced additional asset sales of $9.6 billion which are expected

to close by mid-2013. We continue to evaluate opportunities to further optimize the portfolio.

Commercial Paper and Credit Facilities

In May 2012, we decreased our total revolving credit facilities from $8.0 billion to $7.5 billion by terminating all commitments under the $500 million credit

facility, which was due to expire in July 2012. At

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December 31, 2012, we had a revolving credit facility totaling $7.5 billion expiring in August 2016. Our revolving credit facility may be used as direct bank

borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit

facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring

maintenance of specified financial ratios or ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest

on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.

Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above

the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreement calls for commitment fees on available,

but unused, amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the

Board of Directors.

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper

maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.15 billion commercial paper program, which is used to

fund commitments relating to QG3. At December 31, 2012 and 2011, we had no direct borrowings under the revolving credit facilities, with no letters of credit

issued at December 31, 2012, and $40 million at December 31, 2011. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program,

$1,055 million of commercial paper was outstanding at December 31, 2012, compared with $1,128 million at December 31, 2011. Since we had

$1,055 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.4 billion in borrowing capacity under our revolving

credit facilities at December 31, 2012.

Our senior long-term debt is rated “A1” by Moody’s Investors Service and “A” by both Standard and Poor’s Rating Service and Fitch. We do not have any

ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of

our credit rating. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access

funds under our $7.5 billion revolving credit facility.

Certain of our project-related contracts and derivative instruments contain provisions that require us to post collateral. Cash is the primary source for

providing collateral; however, many permit us to post letters of credit. At December 31, 2012, we had performance obligations secured by letters of credit of

$852 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services

incident to the ordinary conduct of business.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission under which we, as a well-known seasoned issuer,

have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

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Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to

pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.

For information about guarantees, see Note 13—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

For information about our capital expenditures and investments, see the “Capital Spending” section.

Our debt balance at December 31, 2012, was $21.7 billion, a decrease of $0.9 billion during 2012. During 2012, we repaid notes totaling $2.4 billion. We

incurred a before-tax loss on redemption of $79 million, consisting of make-whole premiums and unamortized issuance costs. In December 2012, we issued

$2.0 billion of new low-interest notes.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL. Quarterly principal and interest payments of

$237 million began in the second quarter of 2007 and will continue until the balance is paid. Of the principal obligation amount, approximately $772 million

was short-term and was included in the “Accounts payable—related parties” line on our December 31, 2012, consolidated balance sheet. The principal portion

of these payments, which totaled $733 million in 2012, is included in the “Other” line in the financing activities section of our consolidated statement of cash

flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a

capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

In February, 2013, we announced a dividend of 66 cents per share. The dividend will be paid March 1, 2013, to stockholders of record at the close of

business on February 19, 2013.

Since our share repurchase programs began in 2010, share repurchases totaled 300 million shares at a cost of $20.1 billion through December 31, 2012.

Although we have no current plans for further share repurchases, we may do so opportunistically, contingent upon commodity prices and proceeds from asset

dispositions.

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Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations of our continuing operations as of December 31, 2012:

 Millions of Dollars

 Payments Due by Period 

 Total 

Up to 1

Year Years 2-3 Years 4-5

After

5 Years

Debt obligations (a) $ 21,709 955 1,952 3,274 15,528 

Capital lease obligations 16 - - - 16 

Total debt 21,725 955 1,952 3,274 15,544 

Interest on debt and other obligations 16,355 1,247 2,216 1,964 10,928 

Operating lease obligations 2,151 477 960 424 290 

Purchase obligations (b) 26,465 12,149 4,370 2,242 7,704 

Joint venture acquisition obligation (c) 3,582 772 1,672 1,138 - 

Other long-term liabilities 

Pension and postretirement benefit contributions (d) 2,579 484 1,045 1,050 - 

Asset retirement obligations* 9,033 387 521 413 7,712 

Accrued environmental costs 364 38 6 5 48 213 

Unrecognized tax benefits (e) 116 116 (e) (e) (e) 

Total $ 82,370  16,625  12,801 10,553 42,391 

*Excludes amounts related to discontinued operations: $ 131 - - - 131 

(a) Includes $429 million of net unamortized premiums and discounts. See Note 11—Debt, in the Notes to Consolidated Financial Statements, for

additional information.

(b) Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. Does not include

purchase commitments for jointly owned fields and facilities where we are not the operator.

The majority of the purchase obligations are market-based contracts related to our commodity business. Product purchase commitments with third

parties totaled $12,602 million.

Purchase obligations of $9,629 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including

pipelines and LNG and product terminals, to transport, process, treat and store commodities. The remainder is primarily our net share of purchase

commitments for materials and services for jointly owned fields and facilities where we are the operator.

(c) Represents the remaining amount of contributions, excluding interest, due over a five-year period to the FCCL upstream joint venture with Cenovus.

(d) Represents contributions to qualified and nonqualified pension and postretirement benefit plans for the years 2013 through 2017. For additional

information related to expected benefit payments subsequent to 2017, see Note 19—Employee Benefit Plans, in the Notes to Consolidated Financial

Statements.

(e) Excludes unrecognized tax benefits of $756 million because the ultimate disposition and timing of any payments to be made with regard to such

amounts are not reasonably estimable. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they

represent potential demands on our liquidity.

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Capital Spending

Capital Program Millions of Dollars

 2012 2011 2010

Alaska $ 828 774 729

Lower 48 and Latin America 5,251 3,882 1,790

Canada 2,184 1,761 1,356

Europe 2,860 2,222 1,190

Asia Pacific and Middle East 2,430 2,325 2,157

Other International 415 8 127

LUKOIL Investment - - -

Corporate and Other 204 242 186

Capital expenditures and investments from continuing operations 14,172 11,214 7,535

Discontinued operations in Kashagan, Nigeria and Algeria 817 1,038 1,071

Joint venture acquisition obligation (principal)—Canada 733 695 659

Capital Program $ 15,722  12,947  9,265

Our capital expenditures and investments from continuing operations for the three-year period ended December 31, 2012, totaled $32.9 billion. The

expenditures over this period supported key exploration and developments, primarily:

• Oil, natural gas liquids and natural gas developments in the Lower 48, including Texas, New Mexico, North Dakota, Oklahoma, Montana,

Colorado, Wyoming and offshore in the Gulf of Mexico.

• Further development of coalbed methane (CBM) associated with the APLNG joint venture in Australia.

• Oil sands and ongoing natural gas developments in Canada.

• Alaska activities related to development in the Greater Kuparuk Area, the Greater Prudhoe Area, the Western North Slope and the Cook Inlet Area

and initial development of the Point Thomson Unit.

• Development drilling and new facilities in the Norway sector of the North Sea, including the Greater Ekofisk Area, Alvheim, Visund and

Statfjord, and Heidrun in the Norwegian Sea.

• The Bohai Bay development in China.

• In the U.K. sector of the North Sea, the development of the Jasmine discovery in the J-Area, the development of Clair Ridge and development

drilling in the southern and central North Sea.

• The North Belut Field, as well as other developments in offshore Block B and onshore South Sumatra in Indonesia.

• QG3, an integrated development which produces and liquefies natural gas from Qatar’s North Field.

• The Gumusut-Kakap development offshore Sabah, Malaysia.

• Exploration activities in Australia’s Browse Basin, North American shale plays, Canadian oil sands developments, deepwater Gulf of Mexico,

Alaska, the U.K. and Norway sectors of the North Sea, Kazakhstan and Indonesia.

• Leasehold acquisitions in Angola.

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2013 CAPITAL PROGRAM

Our 2013 capital program of $15.8 billion is comprised of $15.0 billion for the capital expenditures and investments budget and $0.8 billion for principal

contributions to fund our portion of the FCCL business venture. Of the $15.0 billion for the capital expenditures and investments budget, $0.3 billion relates

to our discontinued operations in Kashagan, Nigeria and Algeria and $14.7 billion relates to continuing operations. Included in the 2013 capital expenditures

and investments budget is $0.6 billion in capitalized interest.

Our 2013 capital expenditures and investments budget for continuing operations of $14.7 billion is 4 percent higher than actual expenditures in 2012.

We are directing approximately 60 percent of our 2013 capital expenditures and investments budget for continuing operations to North America. These funds

are expected to be directed toward:

• In Alaska, further development of opportunities in Prudhoe Bay, Kuparuk and Alpine fields, and initial development of Point Thomson Field.

• In Lower 48, development of liquids-rich areas, such as the Eagle Ford trend, and the Williston and Permian basins.

• Exploration and appraisal activities in the Eagle Ford shale formation, and Avalon, Wolfcamp and Niobrara areas in Lower 48.

• Appraisal of deepwater Gulf of Mexico discoveries, wildcat wells and acreage additions.

• Liquids opportunities in the western Canada basins and Canadian oil sands.

• Exploration and appraisal activities in Canadian shale plays and oil sands.

We are directing approximately 40 percent of our 2013 capital expenditures and investments budget for continuing operations to Europe, Asia Pacific and other

international businesses. These funds are expected to be directed toward:

• Further development of CBM associated with the APLNG joint venture in Australia.

• Elsewhere in the Asia Pacific and Middle East segment, continued development of Bohai Bay in China, new fields offshore Malaysia, and

offshore Block B and onshore South Sumatra in Indonesia.

• In the North Sea, the Greater Ekofisk Area, development of the Jasmine discovery in the J-Block Area, development of Clair Ridge and the

Britannia Long Term Compression Project.

• Onshore developments in Libya.

• Exploration and appraisal activities in Australia’s offshore Browse Basin and onshore Canning Basin, deepwater Angola, offshore Indonesia and

Malaysia, and the North Sea.

For information on proved undeveloped reserves and the associated costs to develop these reserves, see the “Oil and Gas Operations” section.

Contingencies

A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be

required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum

substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all

known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a

range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is

accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other

third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax

position is less than certain.

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Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals

by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we

reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent

liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such

factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our

liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as

additional information becomes available during the administrative and litigation processes. For information on other contingencies, see Note 14

—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Legal and Tax Matters

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation

management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential

exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional

judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal

organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, are

required. See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most

significant of these environmental laws and regulations include, among others, the:

• U.S. Federal Clean Air Act, which governs air emissions.

• U.S. Federal Clean Water Act, which governs discharges to water bodies.

• European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH).

• U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators,

transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.

• U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste.

• U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an

area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a

discharge of oil into navigable waters of the United States.

• U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with

local emergency planning committees and response departments.

• U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.

• U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of

pollution cleanup resulting from operations, as well as potential liability for pollution damages.

• European Union Trading Directive resulting in European Emissions Trading Scheme.

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These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in

most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in

connection with the application process, which can be expensive and time consuming. In addition, there can be delays associated with notice and comment

periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of

activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of

marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air

emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those

that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States

and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United

States.

An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas that is otherwise trapped in

lower permeability rock formations. A range of local, state, federal or national laws and regulations currently govern hydraulic fracturing operations. Although

hydraulic fracturing has been conducted for many decades, a number of new laws, regulations and permitting requirements are under consideration by the

U.S. Environmental Protection Agency (EPA), the U.S. Department of the Interior, and others which could result in increased costs, operating restrictions,

operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall

profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards

designed to meet or exceed government requirements. Our practices continually evolve as technology improves and regulations change.

We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws

and regulations include CERCLA and RCRA and their state equivalents. Longer-term expenditures are subject to considerable uncertainty and may fluctuate

significantly.

We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially

responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or

by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but

allegedly contain wastes attributable to our past operations. As of December 31, 2011, we reported we had been notified of potential liability under CERCLA

and comparable state laws at 74 sites around the United States. At December 31, 2012, we had closed 2 sites and transferred 61 sites to Phillips 66, bringing

the number to 11 unresolved sites with potential liability.

For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us,

versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and

several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial

strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased

materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual

cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances,

we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state

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agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost

of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial

condition.

Expensed environmental costs were $575 million in 2012 and are expected to be about $478 million per year in 2013 and 2014. Capitalized environmental

costs were $297 million in 2012 and are expected to be about $459 million per year in 2013 and 2014.

Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those

assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites

where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites

we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If

applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and

RCRA.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation

technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to

develop reasonable estimates of future site remediation costs.

At December 31, 2012, our balance sheet included total accrued environmental costs of $364 million, and we expect to incur a substantial amount of these

expenditures within the next 30 years. At December 31, 2011, accrued environmental costs were $922 million, of which $542 million related to the

Downstream business.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in

our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any

material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

Climate Change

There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed

or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and

while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if

enacted, could have a material impact on our results of operations and financial condition. Examples of legislation or precursors for possible regulation that do

or could affect our operations include:

• European Emissions Trading Scheme (ETS), the program through which many of the European Union (EU) member states are implementing the

Kyoto Protocol. Our cost of compliance with the EU ETS in 2012 was approximately $10 million (pre-tax equity share).

• A regulation issued by the Alberta government in 2007 under the Climate Change and Emissions Act. The regulation requires any existing facility

with emissions equal to or greater than 100,000 metric tons of carbon dioxide or equivalent per year to reduce the net emissions intensity beginning

July 1, 2007 by 12 percent. New facilities must reduce 2 percent per year until they reach the maximum target of 12 percent. We also incur a

carbon tax for emissions from fossil fuel combustion in our British Columbia operations. The total cost of compliance with these Canadian

regulations in 2012 was approximately $7 million.

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• The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007), confirming that the EPA has the authority to

regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.

• The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act

Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final

Rule on April 1, 2010, that triggers regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may

result in longer agency review time for development projects.

• Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon tax legislation in 2012 was approximately $20 million

(equity share pre-tax). In October 2012 the Norwegian government announced a doubling of the carbon tax for oil and gas production in 2013. Cap

and trade programs in certain jurisdictions, including the Australian Clean Energy Legislation which took effect from July 2012. Our annual cost

of compliance with the Australian Clean Energy Legislation during the initial fixed price phase is approximately $10 million (equity share pre-tax).

In the United States, some additional form of regulation may be forthcoming in the future at the federal and state levels with respect to GHG emissions. Such

regulation could take any of several forms that may result in the creation of additional costs in the form of taxes, the restriction of output, investments of

capital to maintain compliance with laws and regulations, or required acquisition or trading of emission allowances. We are working to continuously improve

operational and energy efficiency through resource and energy conservation throughout our operations.

Compliance with changes in laws and regulations that create a GHG emission trading scheme or GHG reduction policies could significantly increase our costs,

reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations

could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive

or negative, will depend on a number of factors, including but not limited to:

• Whether and to what extent legislation is enacted.

• The nature of the legislation (such as a cap and trade system or a tax on emissions).

• The price placed on GHG emissions (either by the market or through a tax).

• The GHG reductions required.

• The price and availability of offsets.

• The amount and allocation of allowances.

• Technological and scientific developments leading to new products or services.

• Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in

temperature).

• Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.

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The Company has responded by putting in place a corporate Climate Change Action Plan, together with individual business unit climate change management

plans in order to undertake actions in four major areas:

• Equipping the Company for a low emission world, for example by integrating GHG forecasting and reporting into company procedures; utilizing

GHG pricing in planning economics; developing systems to handle GHG market transactions.

• Reducing GHG emissions—In 2011 the Company reduced GHG emissions by 600,000 tonnes by carrying out a range of programs across a

number of business units.

• Evaluating business opportunities such as the creation of offsets and allowances; carbon capture and storage; the use of low carbon energy and

the development of low carbon technologies.

• Engaging externally—The Company is a sponsor of MIT’s Joint Program on the Science and Policy of Global Change; constructively engages in

the development of climate change legislation and regulation; and discloses our progress and performance through the Carbon Disclosure Project

and the Dow Jones Sustainability Index.

The Company uses an estimated market cost of GHG emissions in the range of $8 to $46 per tonne depending on the timing and country or region to evaluate

future opportunities.

Other

We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards. Valuation allowances have been established to

reduce these deferred tax assets to an amount that will, more likely than not, be realized. Based on our historical taxable income, our expectations for the

future, and available tax-planning strategies, management expects the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as

reductions in future taxable income.

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CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting

policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1—Accounting

Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve

judgments and uncertainties to such an extent there is a reasonable likelihood materially different amounts would have been reported under different

conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of

Directors at least annually. We believe the following discussions of critical accounting estimates, along with the discussions of contingencies and of deferred

tax asset valuation allowances in this report, address all important accounting areas where the nature of accounting estimates or assumptions is material due to

the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Oil and Gas Accounting

Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and

geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs.

However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas

reserves have been discovered on the prospect.

Property Acquisition Costs

For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold

acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately

will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had

limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is

multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment

charge that is reported in exploration expense.

This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable

exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. At year-end 2012, the

book value of the pools of property acquisition costs that individually are relatively small and thus subject to the above-described periodic leasehold

impairment calculation was $1,915 million and the accumulated impairment reserve was $517 million. The weighted-average judgmental percentage

probability of ultimate failure was approximately 46 percent, and the weighted-average amortization period was approximately four years. If that judgmental

percentage were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2013 would increase by approximately $30 million. At

year-end 2012, the remaining $6,576 million of gross capitalized unproved property costs consisted of individually significant leaseholds, mineral rights

held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells, and capitalized interest. Management periodically

assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for commercialization. Of

this amount, approximately $3 billion is concentrated in 10 major development areas. These major assets are not expected to move to proved properties in 2013.

Exploratory Costs

For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic

oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well.

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If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress

assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental

area, but the accounting rules do prohibit continued capitalization of suspended well costs on the mere chance that future market conditions will improve or

new technologies will be found that would make the development economically profitable. Often, the ability to move into the development phase and record

proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory

well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. Once all required approvals

and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. For complex

exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional

appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek

environmental permitting. Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a

dry hole and reported in exploration expense.

Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses

the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making

this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing

technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.

At year-end 2012, total suspended well costs were $1,038 million, compared with $1,037 million at year-end 2011. For additional information on suspended

wells, including an aging analysis, see Note 7—Suspended Wells, in the Notes to Consolidated Financial Statements.

Proved Reserves

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved

in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan,

historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. The reliability of these estimates at

any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the

hydrocarbons.

Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these

estimates to better understand the perceived value and future cash flows of a company’s operations. There are several authoritative guidelines regarding the

engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineering organization has policies and

procedures in place consistent with these authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our proved

reserves held by consolidated companies, as well as our share of equity affiliates.

Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes occur, and take into account recent production

and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when a field will be permanently

shut down for economic reasons is based on 12-month average prices and year-end costs. This estimated date when production will end affects the amount of

estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.

Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the “economic interest” method and are

subject to fluctuations in commodity prices; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery

of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. The

estimation of proved developed reserves also is important to the income

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statement because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of the DD&A of the

capitalized costs for that asset. At year-end 2012, the net book value of productive properties, plants and equipment (PP&E) subject to a unit-of-production

calculation was approximately $55 billion and the DD&A recorded on these assets in 2012 was approximately $6.4 billion. The estimated proved developed

reserves for our consolidated operations were 5.1 billion BOE at the end of 2011 and 4.9 billion BOE at the end of 2012. If the estimates of proved reserves

used in the unit-of-production calculations had been lower by 5 percent across all calculations, pretax DD&A in 2012 would have increased by an estimated

$336 million.

Impairments

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in

future cash flows expected to be generated by an asset group and annually in the fourth quarter following updates to corporate planning assumptions. If there is

an indication the carrying amount of an asset may not be recovered, the asset is monitored by management through an established process where changes to

significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pretax cash flows

is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment

purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other

groups of assets—generally on a field-by-field basis for exploration and production assets. Because there usually is a lack of quoted market prices for longlived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to

be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of

similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental

assessments of future production volumes, commodity prices, operating costs and capital decisions, considering all available information at the date of review.

See Note 9—Impairments, in the Notes to Consolidated Financial Statements, for additional information.

Investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when there is evidence of a loss in value and

annually following updates to corporate planning assumptions. Such evidence of a loss in value might include our inability to recover the carrying amount, the

lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying

amount. When it is determined such a loss in value is other than temporary, an impairment charge is recognized for the difference between the investment’s

carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as

the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for

a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. When quoted market prices are not available, the

fair value is usually based on the present value of expected future cash flows using discount rates believed to be consistent with those used by principal

market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the

amount of an impairment of an investment in any period.

Asset Retirement Obligations and Environmental Costs

Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of

operations at operational sites. Our largest asset removal obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas

platforms around the world, as well as oil and gas production facilities and pipelines in Alaska. The fair values of obligations for dismantling and removing

these facilities are accrued into PP&E at the time of installation of the asset based on estimated discounted costs. Estimating the future asset removal costs

necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and

regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal

technologies and costs, regulatory and other

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compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to

change.

Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets.

However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in

the asset removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be

subject to impairment, due to the low fair value of these properties.

In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain environmental-related projects. These

are primarily related to remediation activities required by Canada and various states within the United States at exploration and production sites. Future

environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the

unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.

Projected Benefit Obligations

Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such

obligations on the balance sheet and to the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations and

company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement,

mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by

retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations

and company contribution requirements. For Employee Retirement Income Security Act-qualified pension plans, the actuary exercises fiduciary care on behalf

of plan participants in the determination of the judgmental assumptions used in determining required company contributions into the plan. Due to differing

objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial

methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under

pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations

significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on

plan assets assumptions. A 1 percent decrease in the discount rate assumption would increase annual benefit expense by $130 million, while a 1 percent

decrease in the return on plan assets assumption would increase annual benefit expense by $50 million. In determining the discount rate, we use yields on

high-quality fixed income investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility that lump sum

retirement benefits taken from pension plans during the year could exceed the total of service and interest components of annual pension expense and

trigger accelerated recognition of a portion of unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan participants

and are therefore difficult to predict.

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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange

Act of 1934. You can identify our forward-looking statements by 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.

We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in

general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be

incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future

events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the

forward-looking statements. Any differences could result from a variety of factors, including the following:

• Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices.

• Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments due to operating

hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.

• Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.

• Unexpected changes in costs or technical requirements for constructing, modifying or operating exploration and production facilities.

• Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, bitumen and LNG.

• Inability to timely obtain or maintain permits, including those necessary for drilling and/or development, construction of LNG terminals or

regasification facilities; comply with government regulations; or make capital expenditures required to maintain compliance.

• Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future exploration and

production and LNG development.

• Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events, terrorism or

cyber attacks.

• International monetary conditions and exchange controls.

• Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.

• Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.

• Liability resulting from litigation.

• General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in

governmental policies relating to crude oil, bitumen, natural gas, LNG or natural gas liquids pricing, regulation or taxation; other political,

economic or diplomatic developments; and international monetary fluctuations.

• Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.

• Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial

markets.

• Delays in, or our inability to implement, our asset disposition plan.

• Inability to obtain economical financing for development, construction or modification of facilities and general corporate purposes.

• The operation and financing of our joint ventures.

• The factors generally described in Item 1A—Risk Factors in this report.

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Financial Instrument Market Risk

We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in

commodity prices, foreign currency exchange rates or interest rates. We may use financial and commodity-based derivative contracts to manage the risks

produced by changes in the prices of natural gas, crude oil and related products; fluctuations in interest rates and foreign currency exchange rates; or to

capture market opportunities.

Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors that prohibits the use of highly

leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations. The Authority Limitations document also establishes the

Value at Risk (VaR) limits for the company, and compliance with these limits is monitored daily. The Chief Financial Officer monitors risks resulting from

foreign currency exchange rates and interest rates and reports to the Chief Executive Officer. The Executive Vice President of Commercial, Business

Development and Corporate Planning monitors commodity price risk and also reports to the Chief Executive Officer. The Commercial organization manages

our commercial marketing, optimizes our commodity flows and positions, and monitors risks.

Commodity Price Risk

Our Commercial organization uses futures, forwards, swaps and options in various markets to accomplish the following objectives:

 Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed-price sales

contracts, which are often requested by natural gas consumers, to floating market prices.

 Enable us to use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more

profitable locations and storing commodities to capture seasonal or time premiums. We may use derivatives to optimize these activities.

We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the

derivative financial instruments and derivative commodity instruments we hold or issue, including commodity purchases and sales contracts recorded on the

balance sheet at December 31, 2012, as derivative instruments. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period,

the VaR for those instruments issued or held for trading purposes at December 31, 2012 and 2011, was immaterial to our consolidated cash flows and net

income attributable to ConocoPhillips. The VaR for instruments held for purposes other than trading at December 31, 2012 and 2011, was also immaterial to

our cash flows and net income attributable to ConocoPhillips.

Interest Rate Risk

The following table provides information about our financial instruments that are sensitive to changes in U.S. interest rates. The debt portion of the table

presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates

at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is

estimated based on quoted market prices. The joint venture acquisition obligation portion of the table presents principal cash flows of the fixed-rate 5.3 percent

joint venture acquisition obligation owed to FCCL Partnership. The fair value of the obligation is estimated based on the net present value of the future cash

flows, discounted at year-end 2012 and 2011 effective yield rates of 0.7 percent and 1.24 percent, respectively, based on yields of U.S. Treasury securities of

a similar average duration adjusted for ConocoPhillips’ average credit risk spread and the amortizing nature of the obligation principal.

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 Millions of Dollars Except as Indicated

 Debt

Joint Venture

Acquisition Obligation

Expected

Maturity Date 

Fixed

Rate

Maturity 

Average

Interest

Rate

Floating

Rate

Maturity 

Average

Interest

Rate

Fixed

Rate

Maturity 

Average

Interest

Rate

Year-End 2012 

2013 $ 850 5.75 % $ 91 0.25 % $ 772 5.30% 

2014 400 4.75 - - 814 5.30

2015 1,500 4.60 - - 858 5.30

2016 1,273 5.52 964 0.25 904 5.30

2017 1,001 1.06 - - 234 5.30

Remaining years 14,918 6.25 283 0.19 - 5.30

Total $ 19,942 $ 1,338 $ 3,582 

Fair value $ 25,011 $ 1,338 $ 3,968 

Year-End 2011 

2012 $ 918 4.80 % $ 3 0.38 % $ 732 5.30% 

2013 1,262 5.33 - - 772 5.30

2014 1,511 4.77 - - 814 5.30

2015 1,513 4.62 15 2.01 858 5.30

2016 1,287 5.54 1,128 0.51 904 5.30

Remaining years 14,008 6.52 498 0.38 234 5.30

Total $ 20,499 $ 1,644 $ 4,314 

Fair value $ 25,421 $ 1,644 $ 4,820 

Foreign Currency Exchange Risk

We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency exchange rate

changes although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local

currency tax payments, dividends and cash returns from net investments in foreign affiliates to be remitted within the coming year.

At December 31, 2012 and 2011, we held foreign currency exchange forwards hedging cross-border commercial activity and foreign currency exchange swaps

for purposes of mitigating our cash related exposures. Although these forwards and swaps hedge exposures to fluctuations in exchange rates, we elected not to

utilize hedge accounting. As a result, the change in the fair value of these foreign currency exchange derivatives is recorded directly in earnings. Since the gain

or loss on the swaps is offset by the gain or loss from remeasuring the related cash balances, and since our aggregate position in the forwards was not material,

there would be no material impact to our income from an adverse hypothetical 10 percent change in the December 31, 2012, or 2011, exchange rates. The

notional and fair market values of these positions at December 31, 2012 and 2011, were as follows:

6 9
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 In Millions

Foreign Currency Exchange Derivatives Notional* Fair Market Value**

 2012 2011 2012 2011

Sell U.S. dollar, buy euro USD - 219 $ - (8) 

Sell U.S. dollar, buy British pound USD 2,573  790  31 - 

Sell U.S. dollar, buy Canadian dollar USD - 648 - - 

Sell U.S. dollar, buy Norwegian krone USD - 292 - (7) 

Buy U.S. dollar, sell euro USD 7 - - - 

Buy U.S. dollar, sell Norwegian krone USD 90 - - - 

Buy U.S. dollar, sell Canadian dollar USD 43 - (2) - 

Buy euro, sell Norwegian krone EUR - 3 - - 

Buy euro, sell British pound EUR 96 - - - 

Sell euro, buy British pound EUR - 64 - 5 

 *Denominated in U.S. dollars (USD) and euro (EUR).

**Denominated in U.S. dollars.

For additional information about our use of derivative instruments, see Note 16—Financial Instruments and Derivative Contracts, in the Notes to

Consolidated Financial Statements.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONOCOPHILLIPS

INDEX TO FINANCIAL STATEMENTS

 Page

Report of Management

 72 

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements 73 

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting 74 

Consolidated Income Statement for the years ended December 31, 2012, 2011 and 2010 75 

Consolidated Statement of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010 76 

Consolidated Balance Sheet at December 31, 2012 and 2011 77 

Consolidated Statement of Cash Flows for the years ended December 31, 2012, 2011 and 2010 78 

Consolidated Statement of Changes in Equity for the years ended December 31, 2012, 2011 and 2010 79 

Notes to Consolidated Financial Statements 80 

Supplementary Information 

Oil and Gas Operations 135 

Selected Quarterly Financial Data 165 

Condensed Consolidating Financial Information 166 

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Report of Management

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The

consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting

principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on

estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst &

Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by

stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of

stockholders’ and directors’ meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system

was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published

financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only

reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2012. In making this assessment, it used

the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. Based on

our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2012.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2012, and their report is

included herein.

/s/ Ryan M. Lance /s/ Jeff W. Sheets

Ryan M. Lance Jeff W. Sheets

Chairman and Executive Vice President, Finance

Chief Executive Officer and Chief Financial Officer

February 19, 2013

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Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

The Board of Directors and Stockholders

ConocoPhillips

We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2012 and 2011, and the related consolidated statements

of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also

included the related condensed consolidating financial information listed in the Index at Item 8 and financial statement schedule listed in Item 15(a). These

financial statements, condensed consolidating financial information, and schedule are the responsibility of the Company’s management. Our responsibility is

to express an opinion on these financial statements, condensed consolidating financial information, and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that

we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes

examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting

principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits

provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ConocoPhillips at

December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31,

2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related condensed consolidating financial information and

financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the

information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), ConocoPhillips’ internal control

over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of

Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2013

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Report of Independent Registered Public Accounting Firm on

Internal Control Over Financial Reporting

The Board of Directors and Stockholders

ConocoPhillips

We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control

—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). ConocoPhillips’

management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over

financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our

responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that

we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material

respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing

and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered

necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and

the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over

financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect

the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit

preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being

made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or

timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of

effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance

with the policies or procedures may deteriorate.

In our opinion, ConocoPhillips maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the

COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2012 consolidated financial

statements of ConocoPhillips and our report dated February 19, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2013

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Consolidated Income Statement ConocoPhillips 

Years Ended December 31 Millions of Dollars

 2012 2011 2010

Revenues and Other Income 

Sales and other operating revenues $ 57,967 64,196 56,215 

Equity in earnings of affiliates 1,911 1,239 1,376 

Gain on dispositions 1,657 370 5,563 

Other income 469 264 181 

Total Revenues and Other Income 62,004 66,069 63,335 

Costs and Expenses 

Purchased commodities 25,232 29,797 24,854 

Production and operating expenses 6,793 6,426 6,227 

Selling, general and administrative expenses 1,106 865 809 

Exploration expenses 1,500 1,038 1,125 

Depreciation, depletion and amortization 6,580 6,827 8,004 

Impairments 680 321 81 

Taxes other than income taxes 3,546 3,999 2,788 

Accretion on discounted liabilities 394 422 409 

Interest and debt expense 709 954 1,167 

Foreign currency transaction (gains) losses 41 24 (4) 

Total Costs and Expenses 46,581 50,673 45,460 

Income from continuing operations before income taxes 15,423 15,396 17,875 

Provision for income taxes 7,942 8,208 7,570 

Income From Continuing Operations 7,481 7,188 10,305 

Income from discontinued operations* 1,017 5,314 1,112 

Net income 8,498 12,502 11,417 

Less: net income attributable to noncontrolling interests (70) (66) (59) 

Net Income Attributable to ConocoPhillips $ 8,428 12,436 11,358 

Amounts Attributable to ConocoPhillips Common Shareholders: 

Income from continuing operations $ 7,413 7,127 10,251 

Income from discontinued operations 1,015 5,309 1,107 

Net Income $ 8,428 12,436 11,358 

Net Income Attributable to ConocoPhillips Per Share

of Common Stock (dollars) 

Basic 

Continuing operations $ 5.95 5.18 6.93 

Discontinued operations 0.82 3.86 0.75 

Net Income Attributable to ConocoPhillips Per Share of Common Stock $ 6.77 9.04 7.68 

Diluted 

Continuing operations $ 5.91 5.14 6.88 

Discontinued operations 0.81 3.83 0.74 

Net Income Attributable to ConocoPhillips Per Share of Common Stock $ 6.72 8.97 7.62 

Dividends Paid Per Share of Common Stock (dollars) $ 2.64 2.64 2.15 

Average Common Shares Outstanding (in thousands) 

Basic  1,243,799 1,375,035 1,479,330 

Diluted 1,253,093 1,387,100 1,491,067 

*Net of provision for income taxes on discontinued operations of: $ 745 2,291 763 

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Comprehensive Income ConocoPhillips 

Years Ended December 31 Millions of Dollars

 2012 2011 2010

Net Income $ 8,498 12,502 11,417

Other comprehensive income 

Defined benefit plans 

Prior service cost (credit) arising during the period 2 19 (13) 

Reclassification adjustment for amortization of prior service cost (credit) included in net income (5) 2 15 

Net change (3) 21 2 

Net actuarial loss arising during the period (704) (1,185) (9) 

Reclassification adjustment for amortization of net actuarial losses included in net income 430 226 215 

Net change (274) (959) 206 

Nonsponsored plans* 8 (50) 5 

Income taxes on defined benefit plans 132 375 (67) 

Defined benefit plans, net of tax (137) (613) 146 

Unrealized holding gain on securities** - 8 631 

Reclassification adjustment for gain included in net income - (255) (384) 

Income taxes on unrealized holding gain on securities - 89 (89) 

Unrealized gain (loss) on securities, net of tax - (158) 158 

Foreign currency translation adjustments 929 (387) 1,417 

Reclassification adjustment for gain included in net income (155) (516) - 

Income taxes on foreign currency translation adjustments (16) (14) (13) 

Foreign currency translation adjustments, net of tax 758 (917) 1,404 

Hedging activities 6 1 - 

Income taxes on hedging activities - - - 

Hedging activities, net of tax 6 1 - 

Other Comprehensive Income (Loss), Net of Tax 627 (1,687) 1,708 

Comprehensive Income 9,125 10,815 13,125 

Less: comprehensive income attributable to noncontrolling interests (70) (66) (59) 

Comprehensive Income Attributable to ConocoPhillips $ 9,055 10,749 13,066 

 *Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.

**Available-for-sale securities of LUKOIL.

See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet ConocoPhillips 

At December 31 Millions of Dollars

 2012 2011

Assets 

Cash and cash equivalents $ 3,618 5,780 

Short-term investments* - 581 

Restricted cash 748 - 

Accounts and notes receivable (net of allowance of $10 million in 2012 and $30 million in 2011) 8,929 14,648 

Accounts and notes receivable—related parties 253 1,878 

Inventories 965 4,631 

Prepaid expenses and other current assets 9,476 2,700 

Total Current Assets 23,989 30,218 

Investments and long-term receivables 23,489 32,108 

Loans and advances—related parties 1,517 1,675 

Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $58,916 million in

2012 and $65,029 million in 2011) 67,263 84,180 

Goodwill - 3,332 

Intangibles 4 745 

Other assets 882 972 

Total Assets $ 117,144 153,230 

Liabilities 

Accounts payable $ 9,154 17,973 

Accounts payable—related parties 859 1,680 

Short-term debt 955 1,013 

Accrued income and other taxes 3,366 4,220 

Employee benefit obligations 742 1,111 

Other accruals 2,367 2,071 

Total Current Liabilities 17,443 28,068 

Long-term debt 20,770 21,610 

Asset retirement obligations and accrued environmental costs 8,947 9,329 

Joint venture acquisition obligation—related party 2,810 3,582 

Deferred income taxes 13,185 18,040 

Employee benefit obligations 3,346 4,068 

Other liabilities and deferred credits 2,216 2,784 

Total Liabilities 68,717 87,481 

Equity 

Common stock (2,500,000,000 shares authorized at $.01 par value) 

Issued (2012—1,762,247,949 shares; 2011—1,749,550,587) 

Par value 18 17 

Capital in excess of par 45,324 44,725 

Treasury stock (at cost: 2012—542,230,673; 2011—463,880,628) (36,780) (31,787) 

Accumulated other comprehensive income 4,087 3,246 

Unearned employee compensation - (11) 

Retained earnings 35,338 49,049 

Total Common Stockholders’ Equity 47,987 65,239 

Noncontrolling interests 440 510 

Total Equity 48,427 65,749 

Total Liabilities and Equity $ 117,144 153,230 

*Includes marketable securities of: $ - 232 

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows ConocoPhillips

Years Ended December 31 Millions of Dollars

 2012 2011 2010

Cash Flows From Operating Activities 

Net income $ 8,498 12,502 11,417 

Adjustments to reconcile net income to net cash provided by operating activities 

Depreciation, depletion and amortization 6,580 6,827 8,004 

Impairments 680 321 81 

Dry hole costs and leasehold impairments 874 469 476 

Accretion on discounted liabilities 394 422 409 

Deferred taxes 1,397 340 (973) 

Undistributed equity earnings (596) (131) (357) 

Gain on dispositions (1,657) (370) (5,563) 

Income from discontinued operations (1,017) (5,314) (1,112) 

Other (456) (403) (371) 

Working capital adjustments 

Decrease (increase) in accounts and notes receivable (1,866) (938) 324 

Decrease (increase) in inventories 210 (81) (43) 

Decrease (increase) in prepaid expenses and other current assets 513 (300) 150 

Increase (decrease) in accounts payable 1,103 1,297 (18) 

Increase (decrease) in taxes and other accruals (1,199) (688) 1,589 

Net cash provided by continuing operating activities 13,458 13,953 14,013 

Net cash provided by discontinued operations 464 5,693 3,032 

Net Cash Provided by Operating Activities 13,922 19,646 17,045 

Cash Flows From Investing Activities 

Capital expenditures and investments (14,172) (11,214) (7,535) 

Proceeds from asset dispositions 2,132 2,192 14,710 

Net sales (purchases) of short-term investments 597 400 (982) 

Long-term advances/loans—related parties - - (118) 

Collection of advances/loans—related parties 114 98 95 

Other 821 50 218 

Net cash provided by (used in) continuing investing activities (10,508) (8,474) 6,388 

Net cash provided by (used in) discontinued operations (1,119) 1,459 (1,723) 

Net Cash Provided by (Used in) Investing Activities (11,627) (7,015) 4,665 

Cash Flows From Financing Activities 

Issuance of debt 1,996 - 118 

Repayment of debt (2,565) (934) (5,294) 

Special cash distribution from Phillips 66 7,818 - - 

Change in restricted cash (748) - - 

Issuance of company common stock 138 9 6 133 

Repurchase of company common stock (5,098) (11,123) (3,866) 

Dividends paid (3,278) (3,632) (3,175) 

Other (725) (684) (706) 

Net cash used in continuing financing activities (2,462) (16,277) (12,790) 

Net cash used in discontinued operations (2,019) (28) (29) 

Net Cash Used in Financing Activities (4,481) (16,305) (12,819) 

Effect of Exchange Rate Changes on Cash and Cash Equivalents 24 - 21 

Net Change in Cash and Cash Equivalents (2,162) (3,674) 8,912 

Cash and cash equivalents at beginning of period 5,780 9,454 542 

Cash and Cash Equivalents at End of Period $ 3,618 5,780 9,454 

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Changes in Equity ConocoPhillips

 Millions of Dollars

 Attributable to ConocoPhillips

 Common Stock

 

Par

Value 

Capital in

Excess of

Par 

Treasury

Stock

Grantor

Trusts

Accum. Other

Comprehensive

Income (Loss)

Unearned

Employee

Compensation

Retained

Earnings

NonControlling

Interests Total

December 31, 2009 $ 17 43,681 (16,211) (667) 3,225 (76) 32,069 590 62,628 

Net income 11,358 59 11,417 

Other comprehensive income 1,708 1,708 

Dividends paid (3,175) (3,175) 

Repurchase of company common stock (3,866) (3,866) 

Distributions to noncontrolling interests and other (102) (102) 

Distributed under benefit plans 451 34 485 

Recognition of unearned compensation 29 29 

December 31, 2010 $ 17 44,132 (20,077) (633) 4,933 (47) 40,252 547 69,124 

Net income 12,436 66 12,502 

Other comprehensive loss (1,687) (1,687) 

Dividends paid (3,632) (3,632) 

Repurchase of company common stock (11,133) 10 (11,123) 

Distributions to noncontrolling interests and other (103) (103) 

Distributed under benefit plans 593 33 13 639 

Recognition of unearned compensation 36 36 

Transfer to Treasury Stock (610) 610 - 

Other (7) (7) 

December 31, 2011 $ 17 44,725 (31,787) - 3,246 (11) 49,049 510 65,749 

Net income 8,428 70 8,498 

Other comprehensive income 627 627 

Dividends paid (3,278) (3,278) 

Repurchase of company common stock (5,098) (5,098) 

Distributions to noncontrolling interests and other (109) (109) 

Distributed under benefit plans 1 599 105 705 

Recognition of unearned compensation 1 1 11 

Separation of Downstream business 214 (18,880) (31) (18,697) 

Other 19 19 

December 31, 2012 $ 18 45,324 (36,780) - 4,087 - 35,338 440 48,427 

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements ConocoPhillips

Note 1—Accounting Policies

n Consolidation Principles and Investments—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries

and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have

the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence,

the investment is either classified as available-for-sale if fair value is readily determinable, or the cost method is used if fair value is not readily

determinable. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis.

Other securities and investments are generally carried at cost.

As a result of our separation of Phillips 66 on April 30, 2012, the results of operations for our former refining, marketing and transportation

businesses; most of our former Midstream segment; our former Chemicals segment; and our power generation and certain technology operations

included in our former Emerging Businesses segment (collectively, our “Downstream business”), have been classified as discontinued operations for all

periods presented. In addition, the results of operations for our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our

Algerian and Nigerian businesses have been classified as discontinued operations for all periods presented. See Note 2—Discontinued Operations, for

additional information. We have also realigned our reporting segments following the separation of Phillips 66 and have reflected those changes for all

periods presented. We manage our operations through six operating segments, defined by geographic region: Alaska, Lower 48 and Latin America,

Canada, Europe, Asia Pacific and Middle East, and Other International. For additional information, see Note 25—Segment Disclosures and Related

Information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

n Foreign Currency Translation—Adjustments resulting from the process of translating foreign functional currency financial statements into U.S.

dollars are included in accumulated other comprehensive income in common stockholders’ equity. Foreign currency transaction gains and losses are

included in current earnings. Most of our foreign operations use their local currency as the functional currency.

n Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires

management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of

contingent assets and liabilities. Actual results could differ from these estimates.

n Revenue Recognition—Revenues associated with sales of crude oil, bitumen, natural gas, liquefied natural gas (LNG), natural gas liquids and other

items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods

occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

Revenues associated with producing properties in which we have an interest with other producers are recognized based on the actual volumes we sold

during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be

nonrecoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences

between volumes sold and entitlement volumes are generally not significant.

Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are

entered into “in contemplation” of one another, are combined and reported net (i.e., on the same income statement line).

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n Shipping and Handling Costs—We include shipping and handling costs in production and operating expenses for production activities.

Transportation costs related to marketing activities are recorded in purchased commodities. Freight costs billed to customers were recorded as a

component of revenue.

n Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have

original maturities of 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.

n Short-Term Investments—Investments in bank time deposits and marketable securities (commercial paper and government obligations) with original

maturities of greater than 90 days but less than one year are classified as short-term investments. See Note 15—Derivative and Financial Instruments,

for additional information on these held-to-maturity financial instruments.

n Inventories—We have several valuation methods for our various types of inventories and consistently use the following methods for each type of

inventory. Commodity-related inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any

necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match

current inventory costs with current revenues and to meet tax-conformity requirements. Costs include both direct and indirect expenditures incurred in

bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials,

supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued using various methods, including the weightedaverage-cost method, and the first-in, first-out (FIFO) method, consistent with industry practice.

n Fair Value Measurements—We categorize assets and liabilities measured at fair value into one of three different levels depending on the observability

of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are

observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated

inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our

assumptions about pricing by market participants.

n Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. If the right of offset exists and certain other criteria are

met, derivative assets and liabilities with the same counterparty are netted on the balance sheet and the collateral payable or receivable is netted against

derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing

or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings. For derivative

instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately

recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or

losses from derivative instruments that are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign entity are recognized in

other comprehensive income and appear on the balance sheet in accumulated other comprehensive income until the hedged transaction is recognized in

earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the

excess gains or losses will be recognized immediately in earnings.

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n Oil and Gas Exploration and Development—Oil and gas exploration and development costs are accounted for using the successful efforts method of

accounting.

Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants

and equipment (PP&E). Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of

all conditions necessary for reserves to be classified as proved, the associated leasehold costs are reclassified to proved properties.

Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred.

Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable

reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells

encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress

assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual

to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work

on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting.

Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas resources are

designated as proved reserves.

Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work,

and expenses the suspended well costs as dry holes when it judges the potential field does not warrant further investment in the near term. See

Note 7—Suspended Wells, for additional information on suspended wells.

Development Costs—Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depletion and Amortization—Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated

proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved

developed oil and gas reserves.

n Capitalized Interest—Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer.

Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying

assets.

n Intangible Assets Other Than Goodwill—Intangible assets that have finite useful lives are amortized by the straight-line method over their useful

lives. Intangible assets that have indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we

evaluate the remaining useful lives of intangible assets not being amortized to determine whether events and circumstances continue to support indefinite

useful lives. These indefinite lived intangibles are considered impaired if the fair value of the intangible asset is lower than net book value. The fair value

of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of

intangible assets is determined based upon the present values of expected future cash flows using discount rates believed to be consistent with those used

by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.

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n Goodwill—Goodwill resulting from a business combination is not amortized but is tested at least annually for impairment. If the fair value of a

reporting unit is less than the recorded book value of the reporting unit’s assets (including goodwill), less liabilities, then a hypothetical purchase price

allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the

amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is

written down to the new amount. At December 31, 2011, the Company’s remaining goodwill resided in its discontinued Downstream business and had

been evaluated for impairment on a worldwide basis.

n Depreciation and Amortization—Depreciation and amortization of PP&E on producing hydrocarbon properties and certain pipeline assets (those

which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other

PP&E are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly

integrated with other units).

n Impairment of Properties, Plants and Equipment—PP&E used in operations are assessed for impairment whenever changes in facts and

circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group and annually in the fourth

quarter following updates to corporate planning assumptions. If there is an indication the carrying amount of an asset may not be recovered, the asset is

monitored by management through an established process where changes to significant assumptions such as prices, volumes and future development

plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value

is written down to estimated fair value through additional amortization or depreciation provisions and reported as impairments in the periods in which

the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable

cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production

assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on

the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based

on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. Long-lived assets committed by

management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using

a binding negotiated price, if available, or present value of expected future cash flows as previously described.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices

and costs, considering all available evidence at the date of review. The impairment review includes cash flows from proved developed and undeveloped

reserves, including any development expenditures necessary to achieve that production. Additionally, when probable reserves exist, an appropriate riskadjusted amount of these reserves may be included in the impairment calculation.

n Impairment of Investments in Nonconsolidated Entities —Investments in nonconsolidated entities are assessed for impairment whenever changes in

the facts and circumstances indicate a loss in value has occurred and annually following updates to corporate planning assumptions. When such a

condition is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the

impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates believed

to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.

n Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

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n Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with

any gain or loss reflected in the “Gain on dispositions” line of our consolidated income statement. When less than complete units of depreciable property

are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.

n Asset Retirement Obligations and Environmental Costs—The fair value of legal obligations to retire and remove long-lived assets are recorded in

the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we

capitalize this cost by increasing the carrying amount of the related PP&E. If, in subsequent periods, our estimate of this liability changes, we will

record an adjustment to both the liability and PP&E. Over time the liability is increased for the change in its present value, and the capitalized cost in

PP&E is depreciated over the useful life of the related asset. For additional information, see Note 10—Asset Retirement Obligations and Accrued

Environmental Costs, for additional information.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition

caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an

undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can

be reasonably estimated. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is probable and

estimable.

n Guarantees—The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is

subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one

exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability

when we have information indicating the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee

exposure declines over time. We amortize the guarantee liability to the related income statement line item based on the nature of the guarantee. When it

becomes probable that we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and

circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.

n Stock-Based Compensation—We recognize stock-based compensation expense over the shorter of the service period (i.e., the stated period of time

required to earn the award) or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement. We

have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff

vesting.

n Income Taxes—Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial

reporting basis and the tax basis of our assets and liabilities, except for deferred taxes on income considered to be permanently reinvested in certain

foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes.

Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties related to unrecognized tax benefits are reflected in

production and operating expenses.

n Taxes Collected from Customers and Remitted to Governmental Authorities —Sales and value-added taxes are recorded net in taxes other than

income taxes.

n Net Income Per Share of Common Stock—Basic net income per share of common stock is calculated based upon the daily weighted-average number

of common shares outstanding during the year, including unallocated shares held by the stock savings feature of the ConocoPhillips Savings Plan.

Also, this calculation includes fully vested stock and unit awards that have not yet been issued as common stock,

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along with an adjustment to net income for dividend equivalents paid on unvested unit awards that are considered participating securities. Diluted

net income per share of common stock includes unvested stock, unit or option awards granted under our compensation plans and vested but

unexercised stock options, but only to the extent these instruments dilute net income per share, primarily under the treasury-stock method.

Treasury stock and shares held by grantor trusts are excluded from the daily weighted-average number of common shares outstanding in both

calculations. The earnings per share impact of the participating securities is immaterial.

Note 2—Discontinued Operations

Separation of Downstream Business

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66.

After the close of the New York Stock Exchange on April 30, 2012, the shareholders of record as of 5:00 p.m. Eastern time on April 16, 2012 (the Record

Date), received one share of Phillips 66 common stock for every two ConocoPhillips common shares held as of the Record Date.

In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution, primarily using the proceeds from

the $5.8 billion in Senior Notes issued by Phillips 66 in March 2012, as well as a portion of the approximately $3.6 billion in cash transferred to Phillips 66

at separation, comprised of funds received from the $2.0 billion term loan entered into by Phillips 66 immediately prior to the separation, and approximately

$1.6 billion of cash held by Phillips 66 subsidiaries. Pursuant to the private letter ruling from the Internal Revenue Service, the principal funds from the

special cash distribution will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months

following the distribution. At December 31, 2012, the remaining balance of the cash distribution was $748 million and was included in the “Restricted cash”

line on our consolidated balance sheet.

In order to effect the separation and govern our relationship with Phillips 66 after the separation, we entered into a Separation and Distribution Agreement, an

Indemnification and Release Agreement, an Intellectual Property Assignment and License Agreement, a Tax Sharing Agreement, an Employee Matters

Agreement and a Transition Services Agreement. The Separation and Distribution Agreement governs the separation of the Downstream business, the transfer

of assets and other matters related to our relationship with Phillips 66. The Indemnification and Release Agreement provides for cross-indemnities between

Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters. The Intellectual Property Assignment and

License Agreement governs the allocation of intellectual property rights and assets between Phillips 66 and us.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Phillips 66 and ConocoPhillips with respect to taxes, tax

attributes, tax returns, tax proceedings and certain other tax matters. In addition, the Tax Sharing Agreement imposed certain restrictions on Phillips 66 and its

subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that are designed to preserve the taxfree status of the distribution and certain related transactions. The Tax Sharing Agreement sets forth the obligations of Phillips 66 and us as to the filing of tax

returns, the administration of tax proceedings and assistance and cooperation on tax matters.

The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees and nonemployee directors of Phillips 66 and ConocoPhillips, and generally allocates liabilities and responsibilities relating to employee compensation, benefit plans

and programs. The Employee Matters Agreement provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by

ConocoPhillips. In addition, the Employee Matters Agreement provides that each of the parties will be responsible for their respective current employees and

compensation plans for such current employees, and we will be responsible for liabilities relating to former employees who left prior to the separation (other

than in certain instances where a plan or program was sponsored by a company that became part of the Phillips 66 group of companies at the separation). The

Employee Matters

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Agreement sets forth the general principles relating to employee matters and also addresses any special circumstances during the transition period. The

Employee Matters Agreement also provides that (i) the distribution does not constitute a change in control under existing plans, programs, agreements or

arrangements, and (ii) the distribution and the assignment, transfer or continuation of the employment of employees with another entity will not constitute a

severance event under the applicable plans, programs, agreements or arrangements.

The Transition Services Agreement sets forth the terms on which we will provide Phillips 66, and Phillips 66 will provide to us, certain services or functions

Phillips 66 and ConocoPhillips historically have shared. Transition services include administrative, payroll, human resources, data processing,

environmental health and safety, financial audit support, financial transaction support, and other support services, information technology systems and

various other corporate services. The agreement provides for the provision of specified transition services, generally for a period of up to 12 months, with a

possible extension of 6 months (an aggregate of 18 months), on a cost or a cost-plus basis.

The following table presents the carrying value of the major categories of assets and liabilities of Phillips 66, reflected on our consolidated balance sheet at

December 31, 2011:

 

Millions of

Dollars

Assets 

Accounts and notes receivable $ 8,353

Accounts and notes receivable—related parties 1,671

Inventories 3,403

Prepaid expenses and other current assets 443

Total current assets of discontinued operations 13,870

Investments and long-term receivables 10,304

Loans and advances—related parties 1

Net properties, plants and equipment 15,047

Goodwill 3,332

Intangibles 732

Other assets 121

Total assets of discontinued operations $ 43,407

Liabilities 

Accounts payable $ 10,007

Accounts payable—related parties 785

Short-term debt 30

Accrued income and other taxes 967

Employee benefit obligations 76

Other accruals 411

Total current liabilities of discontinued operations 12,276

Long-term debt 361

Asset retirement obligations and accrued environmental costs 787

Deferred income taxes 5,533

Employee benefit obligations 1,057

Other liabilities and deferred credits 417

Total liabilities of discontinued operations $ 20,431

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Sales and other operating revenues and income from discontinued operations related to Phillips 66 were as follows:

 Millions of Dollars

 2012 2011 2010

Sales and other operating revenues from discontinued operations $ 62,109 196,068 146,542

Income from discontinued operations before-tax $ 1,768 6,776 1,438

Income tax expense 534 1,729 470

Income from discontinued operations $ 1,234 5,047 968

Income from discontinued operations after-tax includes transaction, information systems and other costs incurred to effect the separation of $70 million and

$17 million for the years ended December 31, 2012 and 2011. No separation costs were incurred in 2010.

Prior to the separation, commodity sales to Phillips 66 were $4,973 million for the year ended December 31, 2012; $15,822 million for the year ended

December 31, 2011; and $13,412 million for the year ended December 31, 2010. Commodity purchases from Phillips 66 prior to the separation were $166

million for the year ended December 31, 2012; $516 million for the year ended December 31, 2011; and $479 million for the year ended December 31, 2010.

Prior to May 1, 2012, commodity sales and related costs were eliminated in consolidation between ConocoPhillips and Phillips 66. Beginning May 1, 2012,

these revenues and costs represent third-party transactions with Phillips 66. Although we expect certain transactions related to the sale and purchase of crude

oil, natural gas and products to continue in the future with Phillips 66, the expected continuing cash flows are not considered significant; thus, the operations

and cash flows of our former Downstream business are considered to be eliminated from our ongoing operations.

Other Discontinued Operations

As part of our ongoing strategic asset disposition program, we agreed to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan)

and our Algerian and Nigerian businesses (collectively, the “Disposition Group”). The Disposition Group is part of the Other International operating segment.

On November 26, 2012, we notified government authorities in Kazakhstan and co-ventures of our intent to sell the Company’s 8.4 percent interest in

Kashagan to ONGC Videsh Limited. Expected proceeds are approximately $5 billion, which represents the purchase price plus expected working capital and

customary adjustments at closing. The transaction is expected to close by mid-2013. We recorded a pre-tax impairment of $606 million in the fourth quarter of

2012 to reduce the carrying value to fair value, less costs to sell. As of December 31, 2012, the carrying value of the net assets related to our interest in

Kashagan after the impairment adjustment was $5 billion.

On December 18, 2012, we entered into an agreement with Pertamina to sell our wholly owned subsidiary, ConocoPhillips Algeria Ltd., for a total of $1.75

billion plus customary adjustments. The transaction is anticipated to close by mid-2013. We received a deposit of $175 million in December 2012, which is

included in the “Other accruals” line on our consolidated balance sheet and in the “Other” line of cash flows from investing activities on our consolidated

statement of cash flows. The deposit is refundable in the event our co-venturer exercises its preemptive rights, which have been waived, or government

approval is not received. As of December 31, 2012, the net carrying value of our Algerian assets was $669 million.

On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigerian business unit for a total of $1.79 billion plus customary

adjustments. The transaction is anticipated to close by mid-2013, following appropriate consultations with stakeholders. We received a deposit of $435 million

in December 2012, which is included in the “Other accruals” line on our consolidated balance sheet and in the “Other” line of cash flows from investing

activities on our consolidated statement of cash flows. The deposit

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is only refundable in the event of default by us. As of December 31, 2012, the net carrying value of our Nigerian assets was $323 million.

At December 31, 2012, we classified $29 million of loans and advances to related parties in the “Accounts and notes receivable—related parties” line and

$6,905 million of noncurrent assets in the “Prepaid expenses and other current assets” line of our consolidated balance sheet. In addition, we classified $759

million of noncurrent liabilities in the “Accrued income and other taxes” line and $131 million of asset retirement obligations in the “Other accruals” line of our

consolidated balance sheet. The carrying amounts of the major classes of assets and liabilities associated with the Disposition Group at December 31 were as

follows:

 

 Millions of Dollars 

 2012 2011

Assets 

Accounts and notes receivable $ 268 255

Accounts and notes receivable—related parties 1 4

Inventories 44 48

Prepaid expenses and other current assets 220 279

Total current assets of discontinued operations 533 586

Investments and long-term receivables 272 261

Loans and advances—related parties 29 13

Net properties, plants and equipment 6,629 6,657

Other assets 4 9

Total assets of discontinued operations $ 7,467 7,526

Liabilities 

Accounts payable $ 471 644

Accrued income and other taxes 125 185

Employee benefit obligations - 1

Total current liabilities of discontinued operations 596 830

Asset retirement obligations and accrued environmental costs 131 138

Deferred income taxes 759 989

Total liabilities of discontinued operations $ 1,486 1,957

Sales and other operating revenues and income from discontinued operations related to the Disposition Group during 2012, 2011 and 2010 were as follows:

 

 Millions of Dollars 

 2012 2011 2010

Sales and other operating revenues from discontinued operations $ 1,369 1,560 1,081

Income (loss) from discontinued operations before-tax $ (6) 829 437

Income tax expense 211 562 293

Income (loss) from discontinued operations $ (217) 267 144

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Note 3—Variable Interest Entities (VIEs)

We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on our significant VIEs

follows:

Freeport LNG Development, L.P. (Freeport LNG)

We have an agreement with Freeport LNG to participate in a liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in

Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We

entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a longterm agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity. The terminal became operational in June 2008, and we began

making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was

$565 million at December 31, 2012. Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of Freeport LNG

do not have any substantive decision making ability. Since we do not have the unilateral power to direct the key activities which most significantly impact its

economic performance, we are not the primary beneficiary of Freeport LNG. These key activities primarily involve or relate to operating and maintaining the

terminal. We also performed an analysis of the expected losses and determined we are not the primary beneficiary. This expected loss analysis took into

account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial insurance to mitigate any loan losses. The loan to

Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity investment.

Australia Pacific LNG (APLNG)

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support.

We are not the primary beneficiary of APLNG because we share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the

key activities of APLNG that most significantly impact its economic performance, which involve activities related to the production and commercialization of

coalbed methane, as well as LNG processing and export marketing. As a result, we do not consolidate APLNG, and it is accounted for as an equity method

investment.

As of December 31, 2012, we have not provided, nor do we expect to provide in the future, any financial support to APLNG other than amounts previously

contractually required. In addition, unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 6

—Investments, Loans and Long-Term Receivables, and Note 13—Guarantees, for additional information.

Note 4—Inventories

Inventories at December 31 were:

 

 Millions of Dollars 

 2012 2011 

Crude oil and petroleum products $ 244 3,633 

Materials, supplies and other 721 998 

 $ 965 4,631 

Inventories valued on the LIFO basis totaled $147 million and $3,387 million at December 31, 2012 and 2011, respectively. The estimated excess of current

replacement cost over LIFO cost of inventories amounted to approximately $200 million and $8,400 million at December 31, 2012 and 2011, respectively. In

2012, a liquidation of LIFO inventory values increased net income from continuing operations by $32 million.

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A significant portion of our inventories at December 31, 2011, was related to our Downstream business. See Note 2—Discontinued Operations, for additional

information.

Note 5—Assets Held for Sale or Sold

Assets Held for Sale

Our interest in Kashagan and the Algerian and Nigerian business units were considered held for sale as of December 31, 2012. These assets are classified as

discontinued operations. See Note 2—Discontinued Operations.

In January 2013, we entered into an agreement to sell the majority of our properties in the Cedar Creek Anticline (CCA) to Denbury Resources for $1.05 billion

plus customary adjustments. The transaction is expected to close in the first quarter of 2013. CCA is included in our Lower 48 and Latin America segment. At

December 31, 2012, the asset was considered held for sale. In December 2012, we recorded a pre-tax impairment of $192 million to reduce the carrying value

to fair value. We also reclassified $1.08 billion of related noncurrent assets, primarily PP&E, to “Prepaid expenses and other current assets” and $426 million

of noncurrent liabilities, comprised of deferred tax liabilities and asset retirement obligations (ARO), to “Accrued income and other taxes” and “Other

accruals”.

Assets Sold

All gains are reported before-tax and are included in the “Gain on dispositions” line on the consolidated income statement.

2012

In March 2012, we sold our Vietnam business for $1,095 million, including customary working capital adjustments, and recognized a gain of $931 million.

At the time of the disposition, the net carrying value of the business, which was included in the Asia Pacific and Middle East segment, was approximately

$164 million, which included $352 million of PP&E, $69 million of ARO and $145 million of deferred income taxes.

In April 2012, we sold our interest in the Statfjord Field and associated satellites, all of which are located in the North Sea, for $228 million and recognized a

gain of $429 million. At the time of disposition, the carrying value of our interest, which was included in the Europe segment, was negative $201 million,

which included $205 million of PP&E and $445 million of ARO.

In May 2012, we sold our interest in the North Sea Alba Field for $220 million, and recognized a gain of $155 million. At the time of disposition, the

carrying value of our interest, which was included in the Europe segment, was $65 million, which included $160 million of PP&E and $86 million of ARO.

In August 2012, we sold our 30 percent interest in Naryanmarneftegaz (NMNG) and certain related assets for $450 million, and recognized a gain of $206

million. At the time of the disposition, the carrying value of our equity investment in NMNG, which was included in the Other International segment, was

$244 million.

2011

In the first quarter of 2011, we sold the remainder of our interest in LUKOIL for cash proceeds of $1,243 million, and recognized a gain of $360 million.

2010

During 2010, we sold a portion of our interest in LUKOIL, consisting of 151 million shares, for $8,345 million, and recognized a gain of $1,749 million.

The cost basis for the shares, which were classified as available-for-sale, was average cost.

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In June 2010, we sold our 9.03 percent interest in the Syncrude Canada Ltd. joint venture for $4.6 billion, and recognized a gain of $2.9 billion. At the time of

disposition, Syncrude had a net carrying value of $1.75 billion, which included $1.97 billion of PP&E.

Note 6—Investments, Loans and Long-Term Receivables

Components of investments, loans and long-term receivables at December 31 were:

 

 Millions of Dollars 

 2012 2011 

Equity investments $ 22,431 30,985 

Loans and advances—related parties 1,517 1,675 

Long-term receivables 609 559 

Other investments 449 564 

 $ 25,006 33,783 

Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2012, included:

• Australia Pacific LNG Pty Ltd (APLNG)—37.5 percent owned joint venture with Origin Energy (37.5 percent) and China Petrochemical

Corporation (Sinopec) (25 percent)—to develop coalbed methane production from the Bowen and Surat basins in Queensland, Australia, as well

as process and export LNG.

• FCCL Partnership—50 percent owned business venture with Cenovus Energy Inc.—produces bitumen in the Athabasca oil sands in northeastern

Alberta and sells the bitumen blend.

• Qatar Liquefied Gas Company Limited 3 (QG3)—30 percent owned joint venture with affiliates of Qatar Petroleum (68.5 percent) and Mitsui &

Co., Ltd. (1.5 percent)—produces and liquefies natural gas from Qatar’s North Field.

Prior to the separation of the Downstream business, we also had significant equity investments in the following affiliated companies:

• WRB Refining LP—50 percent owned business venture with Cenovus—owns the Wood River and Borger refineries, which process crude oil into

refined products.

• DCP Midstream, LLC—50 percent owned joint venture with Spectra Energy—owns and operates gas plants, gathering systems, storage facilities

and fractionation plants.

• Chevron Phillips Chemical Company LLC—50 percent owned joint venture with Chevron Corporation—manufactures and markets

petrochemicals and plastics.

We no longer hold significant equity investments in these affiliated companies as a result of the separation of the Downstream business. See Note 2

—Discontinued Operations, for additional information.

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Summarized 100 percent earnings information for equity method investments in affiliated companies, combined, was as follows (information includes

LUKOIL until loss of significant influence as well as equity investments disposed of in connection with the separation of the Downstream business until the

date of the separation):

 

 Millions of Dollars 

 2012 2011 2010 

Revenues $ 17,903 77,263 105,589 

Income before income taxes 5,986 11,958 11,250 

Net income 5,767 11,089 9,495 

Summarized 100 percent balance sheet information for equity method investments in affiliated companies, combined, was as follows (information includes

equity investments disposed of in connection with the separation of the Downstream business until the date of the separation):

 

 Millions of Dollars 

 2012 2011 

Current assets $ 11,510 21,530 

Noncurrent assets 46,743 76,300 

Current liabilities 3,721 9,708 

Noncurrent liabilities 9,698 22,993 

Our share of income taxes incurred directly by the equity companies is reported in equity in earnings of affiliates, and as such is not included in income taxes

in our consolidated financial statements.

At December 31, 2012, retained earnings included $803 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates

were $1,351 million, $3,670 million and $2,282 million in 2012, 2011 and 2010, respectively.

APLNG

In 2008, we closed on a transaction with Origin Energy, an integrated Australian energy company, to further enhance our long-term Australasian natural gas

business. APLNG is focused on coalbed methane production from the Bowen and Surat basins in Queensland, Australia, and LNG processing and export

sales. This transaction gives us access to coalbed methane resources in Australia and enhances our LNG position with the expected creation of an additional

LNG hub targeting the Asia Pacific markets. Origin is the operator of APLNG’s production and pipeline system, while we will operate the LNG facility.

In April 2011, APLNG and Sinopec signed definitive agreements for APLNG to supply up to 4.3 million tonnes of LNG per year for 20 years. The agreements

also specified terms under which Sinopec subscribed for a 15 percent equity interest in APLNG, with both our ownership interest and Origin Energy’s

ownership interest diluting to 42.5 percent. The Subscription Agreement was completed in August 2011, and we recorded a loss on disposition of $279

million before- and after-tax from the dilution. The book value of our investment in APLNG was reduced by $795 million, and we reduced the currency

translation adjustment associated with our investment by $516 million.

In January 2012, APLNG and Sinopec signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million

tonnes of LNG per year through 2035. This agreement, in combination with the execution of an LNG sale and purchase agreement with The Kansai Electric

Power Co. Inc., in June 2012 for approximately 1.0 million tonnes of LNG per year through 2035, finalized the marketing of the second train.

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In July 2012, the APLNG co-venturers sanctioned the development of a second 4.5-million-tonnes-per-year LNG production train. Upon sanctioning of the

second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed to additional shares in APLNG, which increased its equity interest

from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin’s ownership interest diluted from 42.5 percent to 37.5

percent. We recorded a before- and after-tax loss of $133 million from the dilution in the third quarter of 2012. The book value of our investment in APLNG

was reduced by $453 million, and we reduced the foreign currency translation adjustment associated with our investment by $320 million.

In addition, APLNG executed project financing agreements for an $8.5 billion project finance facility during the third quarter of 2012. The $8.5 billion

project finance facility is composed of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $2.9

billion, the Export-Import Bank of China for approximately $2.7 billion, and a syndicate of Australian and international commercial banks for approximately

$2.9 billion. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility

which will be released upon meeting certain completion milestones. See Note 13—Guarantees, for additional information.

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support.

See Note 3—Variable Interest Entities (VIEs) for additional information.

At December 31, 2012, the book value of our equity method investment in APLNG was $10,394 million, which includes $2,568 million of cumulative

translation effects due to a strengthening Australian dollar relative to the U.S. dollar. The historical cost basis of our 37.5 percent share of net assets on the

books of APLNG under U.S. generally accepted accounting principles was $3,961 million, resulting in a basis difference of $6,433 million on our books.

The amortizable portion of the basis difference, $4,686 million associated with PP&E, has been allocated on a relative fair value basis to individual

exploration and production license areas owned by APLNG, most of which are not currently in production. Any future additional payments are expected to be

allocated in a similar manner. Each exploration license area will periodically be reviewed for any indicators of potential impairment, which, if required, would

result in acceleration of basis difference amortization. As the joint venture begins producing natural gas from each license, we amortize the basis difference

allocated to that license using the unit-of-production method. Included in net income attributable to ConocoPhillips for 2012, 2011 and 2010 was after-tax

expense of $19 million, $17 million and $5 million, respectively, representing the amortization of this basis difference on currently producing licenses.

FCCL

FCCL Partnership, a Canadian upstream 50/50 general partnership with Cenovus Energy Inc., produces bitumen in the Athabasca oil sands in northeastern

Alberta and sells the bitumen blend. We account for our investment in FCCL under the equity method of accounting, with the operating results of our

investment in FCCL converted to reflect the use of the successful efforts method of accounting for oil and gas exploration and development activities.

At December 31, 2012, the book value of our investment in FCCL was $9,972 million. FCCL’s operating assets consist of the Foster Creek and Christina

Lake steam-assisted gravity drainage bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeastern Alberta. Cenovus is the

operator and managing partner of FCCL. We are obligated to contribute $7.5 billion, plus accrued interest, to FCCL over a 10-year period that began in 2007.

For additional information on this obligation, see Note 12—Joint Venture Acquisition Obligation.

QG3

QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project financing, with a current outstanding balance of

$1,092 million as described below under “Loans and Long-term Receivables.” At December 31, 2012, the book value of our equity method investment in

QG3 excluding the project financing was $984 million. We have terminal and pipeline use agreements with Golden Pass LNG

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Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, in which we have a 12.4 percent interest, intended to provide us with terminal and

pipeline capacity for the receipt, storage and regasification of LNG purchased from QG3. However, currently the LNG from QG3 is being sold to markets

outside of the United States.

Loans and Long-term Receivables

As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue

business opportunities. Included in such activity are loans and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded

when cash is transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan agreement. The loan balance will increase

as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s

stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.

At December 31, 2012, significant loans to affiliated companies include the following:

• $565 million in loan financing to Freeport LNG Development, L.P. for the construction of an LNG receiving terminal that became operational in

June 2008. Freeport began making repayments in 2008 and is required to continue making repayments through full repayment of the loan in 2026.

Repayment by Freeport is supported by “process-or-pay” capacity service payments made by us to Freeport under our terminal use agreement.

• $1,092 million in project financing to QG3. We own a 30 percent interest in QG3, for which we use the equity method of accounting. The other

participants in the project are affiliates of Qatar Petroleum and Mitsui. QG3 secured project financing of $4.0 billion in December 2005,

consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from

ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. On

December 15, 2011, QG3 achieved financial completion and all project loan facilities became nonrecourse to the project participants. Semi-annual

repayments began in January 2011 and will extend through July 2022.

The long-term portion of these loans are included in the “Loans and advances—related parties” line on our consolidated balance sheet, while the short-term

portion is in “Accounts and notes receivable—related parties.”

Note 7—Suspended Wells

The following table reflects the net changes in suspended exploratory well costs during 2012, 2011, and 2010:

 

 Millions of Dollars 

 2012 2011 2010 

Beginning balance at January 1 $ 1,037 1,013 908 

Additions pending the determination of proved reserves 185 96 216 

Reclassifications to proved properties (144) (72) (106) 

Sales of suspended well investment (18) - 

 (4) 

Charged to dry hole expense (22) - 

 (1) 

Ending balance at December 31 $ 1,038 * 1,037 1,013 

*Includes$190 million of assets held for sale—$133 million in Kazakhstan and $57 million in Nigeria.

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The following table provides an aging of suspended well balances at December 31, 2012, 2011 and 2010:

 

 Millions of Dollars 

 2012 2011 2010 

Exploratory well costs capitalized for a period of one year or less $ 186 115 220 

Exploratory well costs capitalized for a period greater than one year 852 922 793 

Ending balance $ 1,038 * 1,037 1,013 

Number of projects with exploratory well costs capitalized for a period greater than one year 35 40 40 

*Includes$190 million of assets held for sale—$133 million in Kazakhstan and $57 million in Nigeria.

The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as

of December 31, 2012:

 Millions of Dollars

 Suspended Since

 Total 2009-2011 2006-2008 2001-2005 

Aktote—Kazakhstan $ 19 - - 19 

Alpine Satellite—Alaska 23 - - 23 

Browse Basin—Australia 216 216 - - 

Caldita/Barossa—Australia 78 - 44 34 

Clair SW—UK 14 14 - - 

Fiord West—Alaska 16 - 16 - 

Kairan—Kazakhstan 27 - 14 13 

Kalamkas—Kazakhstan 14 5 5 4 

Kashagan II—Kazakhstan 45 9 26 10 

Muskwa—Canada 5 6 5 6 - - 

NPR-A—Alaska 17 17 - - 

Pisagan—Malaysia 10 - - 10 

Saleski—Canada 18 - 18 - 

Shenandoah—Lower 48 43 43 - - 

Sunrise 3—Australia 13 - 13 - 

Surmont 3 and beyond—Canada 45 21 22 2 

Thornbury—Canada 21 - 21 - 

Tiber—Lower 48 40 40 - - 

Titan—Norway 12 12 - - 

Ubah—Malaysia 36 11 25 - 

Uge—Nigeria 30 - 16 14 

Other of $10 million or less each 5 9 17 40 2 

Total $ 852 461 260 131 

(1)Additional appraisal wells planned.

(2)Appraisal drilling complete; costs being incurred to assess development.

(3)Assets held for sale as of December 31, 2012.

9 5

(2)(3)

(2)

(1)

(1)

(1)

(2)

(2)(3)

(2)(3)

(2)(3)

(1)

(2)

(2)

(1)

(1)

(2)

(1)

(1)

(1)

(2)

(2)

(2)(3)

(1)(2)
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Note 8—Goodwill and Intangibles

Goodwill

Changes in the carrying amount of goodwill, all associated with the Downstream business, were as follows:

 

 Millions of Dollars 

 2012 2011 

Goodwill balance as of January 1 $ 3,332 3,633 

Goodwill allocated to assets held for sale or sold - (273) 

Tax and other adjustments (2) (28) 

Separation of Downstream business (3,330) - 

Goodwill balance as of December 31 $ - 3,332 

Intangible Assets

At year-end 2012, our intangible asset balance was $4 million, compared with $745 million at year-end 2011. Intangible assets of $730 million related to our

Downstream business and were transferred to Phillips 66 upon the separation.

Note 9—Impairments

During 2012, 2011 and 2010, we recognized the following before-tax impairment charges:

 

 Millions of Dollars 

 2012 2011 2010 

Alaska $ 3 2 6 

Lower 48 and Latin America 192 71 19 

Canada 262 253 13 

Europe 211 (37) 43 

Asia Pacific and Middle East 4 - - 

Corporate 8 32 - 

 $ 680 321 81 

2012

In 2012, we recorded a $192 million property impairment in the Lower 48 and Latin America segment related to the planned disposition of Cedar Creek

Anticline, located in southwestern North Dakota and eastern Montana.

The Canada segment included a $213 million property impairment for the carrying value of capitalized project development costs associated with our

Mackenzie Gas Project. Advancement of the project was suspended indefinitely in the first quarter of 2012 due to a continued decline in market conditions and

the lack of acceptable commercial terms. We also recorded a $481 million impairment for the undeveloped leasehold costs associated with the project, which

was included in the “Exploration expenses” line on our consolidated income statement. Additionally, we recorded impairments on various producing and nonproducing properties.

In Europe, we recorded impairments of $211 million, mainly related to ARO revisions for properties which have ceased production or are nearing the end of

their useful lives.

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2011

During 2011, we recorded property impairments of $289 million, primarily in our Lower 48 and Latin America and Canada segments, largely as a result of

lower natural gas price assumptions and reduced volume forecasts.

2010

During 2010, we recorded various property impairments of $81 million, primarily in our Europe and Lower 48 and Latin America segments.

Note 10—Asset Retirement Obligations and Accrued Environmental Costs

Asset retirement obligations and accrued environmental costs at December 31 were:

 

 Millions of Dollars 

 2012 2011 

Asset retirement obligations $ 9,164 8,920 

Accrued environmental costs 364 922 

Total asset retirement obligations and accrued environmental costs 9,528 9,842 

Asset retirement obligations and accrued environmental costs due within one year* (581) (513) 

Long-term asset retirement obligations and accrued environmental costs $ 8,947 9,329 

* Classified as a current liability on the balance sheet under “Other accruals” and includes $158 million of liabilities associated with assets

held for sale at December 31, 2012. 

Asset Retirement Obligations

We record the fair value of a liability for an asset retirement obligation when it is incurred (typically when the asset is installed at the production location).

When the liability is initially recorded, we capitalize the associated asset retirement cost by increasing the carrying amount of the related PP&E. If, in

subsequent periods, our estimate of this liability changes, we will record an adjustment to both the liability and PP&E. Over time, the liability increases for

the change in its present value, while the capitalized cost depreciates over the useful life of the related asset.

We have numerous asset removal obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of

these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of

removal. Our largest individual obligations involve plugging and abandonment of wells and removal and disposal of offshore oil and gas platforms around the

world, as well as oil and gas production facilities and pipelines in Alaska.

During 2012 and 2011, our overall asset retirement obligation changed as follows:

 

 Millions of Dollars 

 2012 2011 

Balance at January 1 $ 8,920 8,776 

Accretion of discount 412 435 

New obligations 315 153 

Changes in estimates of existing obligations 543 29 

Spending on existing obligations (319) (327) 

Property dispositions (607) (60) 

Foreign currency translation 281 (86) 

Separation of Downstream business (381) - 

Balance at December 31 $ 9,164 8,920 

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Accrued Environmental Costs

Total accrued environmental costs at December 31, 2012 and 2011, were $364 million and $922 million, respectively. A significant portion of our

environmental contingencies at December 31, 2011, related to our Downstream business. See Note 2—Discontinued Operations, for additional information.

The remaining 2012 decrease in total accrued environmental costs is due to payments and settlements during the year exceeding new accruals, accrual

adjustments and accretion.

We had accrued environmental costs of $279 million and $571 million at December 31, 2012 and 2011, respectively, related to remediation activities required

by Canada and various states within the U.S. at operated sites. We had also accrued in Corporate and Other $70 million and $274 million of environmental

costs associated with nonoperator sites at December 31, 2012 and 2011, respectively. In addition, $15 million and $77 million were included at both

December 31, 2012 and 2011, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive

Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods

extending up to 30 years.

Because a large portion of the accrued environmental costs were acquired in various business combinations, they are discounted obligations. Expected

expenditures for acquired environmental obligations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for

acquired environmental liabilities of $142 million at December 31, 2012. The expected future undiscounted payments related to the portion of the accrued

environmental costs that have been discounted are: $20 million in 2013, $16 million in 2014, $14 million in 2015, $8 million in 2016, $7 million in 2017,

and $98 million for all future years after 2017.

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Note 11—Debt

Long-term debt at December 31 was:

 

 Millions of Dollars 

 2012 2011 

9.125% Debentures due 2021 $ 150 150

8.20% Debentures due 2025 150 150 

8.125% Notes due 2030 600 600 

7.9% Debentures due 2047 100 100 

7.8% Debentures due 2027 300 300 

7.68% Notes due 2012 - 7 

7.65% Debentures due 2023 88 88 

7.625% Debentures due 2013 100 100 

7.40% Notes due 2031 500 500 

7.375% Debentures due 2029 92 92 

7.25% Notes due 2031 500 500 

7.20% Notes due 2031 575 575 

7% Debentures due 2029 200 200 

6.95% Notes due 2029 1,549 1,549 

6.875% Debentures due 2026 67 67 

6.65% Debentures due 2018 297 297 

6.50% Notes due 2039 2,250 2,250 

6.50% Notes due 2039 500 500 

6.00% Notes due 2020 1,000 1,000 

5.951% Notes due 2037 645 645 

5.95% Notes due 2036 500 500 

5.90% Notes due 2032 505 505 

5.90% Notes due 2038 600 600 

5.75% Notes due 2019 2,250 2,250 

5.625% Notes due 2016 1,250 1,250 

5.50% Notes due 2013 750 750 

5.20% Notes due 2018 500 500 

4.75% Notes due 2012 - 897 

4.75% Notes due 2014 400 1,500 

4.60% Notes due 2015 1,500 1,500 

4.40% Notes due 2013 - 400 

2.4% Notes due 2022 1,000 - 

1.05% Notes due 2017 1,000 - 

Commercial paper at 0.15% – 0.252% at year-end 2012 and 0.34% – 0.341% at

year-end 2011 1,055 1,128 

Industrial Development Bonds due 2012 through 2038 at 0.04% – 0.11% at

year-end 2012 and 0.08% – 5.75% at year-end 2011 18 252 

Guarantee of savings plan bank loan payable due 2015 at 2.29% at year-end 2011 - 15 

Note payable to Merey Sweeny, L.P. due 2020 at 7% (related party) - 133 

Marine Terminal Revenue Refunding Bonds due 2031 at 0.08% – 0.2% at

year-end 2012 and 0.08% – 0.15% at year-end 2011 265 265 

Other 24 28 

Debt at face value 21,280 22,143 

Capitalized leases 16 31 

Net unamortized premiums and discounts 429 449 

Total debt 21,725 22,623 

Short-term debt (955) (1,013) 

Long-term debt $ 20,770 21,610 

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Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2013 through 2017 are: $955 million, $414 million, $1,538

million, $2,254 million and $1,020 million, respectively. At December 31, 2012, we classified $964 million of short-term debt as long-term debt, based on

our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.

During 2012, the following new debt instruments were issued:

• The $1,000 million 1.05% Notes due 2017.

• The $1,000 million 2.40% Notes due 2022.

During 2012, the following debt instruments were repaid:

• The $400 million 4.40% Notes due 2013, repaid before maturity.

• $1,100 million of the $1,500 million 4.75% Notes due 2014, repaid before maturity.

• The $897 million of 4.75% Notes due 2012, repaid at maturity.

We incurred a before-tax loss on redemption of $79 million related to the two debt instruments we repaid before maturity, consisting of a make-whole premium

and unamortized issuance costs.

In May 2012, we decreased our total revolving credit facilities from $8.0 billion to $7.5 billion by terminating all commitments under the $500 million credit

facility which was due to expire in July 2012. Our revolving credit facility may be used as direct bank borrowings, as support for issuances of letters of credit

totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facility is broadly syndicated among financial institutions

and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility

agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by

ConocoPhillips, or by any of its consolidated subsidiaries.

Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above

the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreements call for commitment fees on available,

but unused, amounts. The agreements also contain early termination rights if our current directors or their approved successors cease to be a majority of the

Board of Directors.

We have two commercial paper programs: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and

the ConocoPhillips Qatar Funding Ltd. $1.15 billion commercial paper program, which is used to fund commitments relating to the QG3 Project. Commercial

paper maturities are generally limited to 90 days. At both December 31, 2012 and 2011, we had no direct outstanding borrowings under the revolving credit

facilities, with no letters of credit as of December 31, 2012, and $40 million as of December 31, 2011. In addition, under the ConocoPhillips Qatar Funding

Ltd. commercial paper program, there was $1,055 million of commercial paper outstanding at December 31, 2012, compared with $1,128 million at

December 31, 2011. Since we had $1,055 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.4 billion in

borrowing capacity under our revolving credit facilities at December 31, 2012.

Note 12—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL. Quarterly principal and interest payments of

$237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, $772 million was short-term

and was included in the “Accounts payable—related parties” line on our December 31, 2012 consolidated balance sheet. The principal portion of these

payments, which totaled $733 million in 2012, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows.

Interest accrues at a fixed

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annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included

in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

Note 13—Guarantees

At December 31, 2012, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability at

inception for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below,

we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial.

In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either

immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At December 31, 2012, we have outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a

description of the guarantees with values calculated utilizing December 2012 exchange rates:

• We have guaranteed APLNG’s performance with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1

and Train 2 Notices to Proceed. We estimate the remaining term of this guarantee is 4 years. Our maximum potential amount of future payments

related to this guarantee is approximately $180 million and would become payable if APLNG cancels the applicable construction contract and

does not perform with respect to the amounts owed to the contractor.

• We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. Our maximum potential

amount of future payments under the guarantee is estimated to be $3.2 billion, which could be payable if the full debt financing capacity is

utilized and completion of the project is not achieved. Our guarantee of the project financing will be released upon meeting certain completion

milestones, which we estimate would occur beginning in 2016. Our maximum exposure at December 31, 2012, is $860 million based upon our

pro-rata share of the facility used at that date. At December 31, 2012, the carrying value of this guarantee is approximately $114 million.

• In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to guarantee an

existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 4 to 19 years. Our maximum potential

amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1.0 billion ($2.4 billion in the event of

intentional or reckless breach) and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot

otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG

does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into

APLNG.

• We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued

development. The guarantees have remaining terms of up to 33 years or the life of the venture. Our maximum potential amount of future payments

related to these guarantees is approximately $150 million and would become payable if APLNG does not perform.

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Guarantees of Joint Venture Debt

At December 31, 2012, we had guarantees outstanding for our portion of joint venture debt obligations, which have remaining terms of up to 23 years. The

maximum potential amount of future payments under the guarantees is approximately $60 million. Payment would be required if a joint venture defaults on its

debt obligations.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $270 million, which consist primarily of guarantees of the

residual value of leased corporate aircraft, guarantees to fund the short-term cash liquidity deficit of two joint ventures and a guarantee of minimum charter

revenue for an LNG vessel. These guarantees have remaining terms of up to 11 years or life of the venture.

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying

indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims,

real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related

to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded

for these indemnifications at December 31, 2012, was approximately $70 million. We amortize the indemnification liability over the relevant time period, if one

exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the

liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our

indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications,

it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount were

approximately $50 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued

environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 14—Contingencies and

Commitments.

In connection with the separation of the Downstream business, the Company entered into an Indemnification and Release Agreement with Phillips 66. See Note

2—Discontinued Operations, for additional information. This agreement provides for cross-indemnities between Phillips 66 and ConocoPhillips and

established procedures for handling claims subject to indemnification and related matters. We evaluated the impact of the indemnifications given and the

Phillips 66 indemnifications received as of the separation date and concluded those fair values were immaterial.

Note 14—Contingencies and Commitments

A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be

required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum

substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all

known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a

range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is

accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other

third-party recoveries. In the case of income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax

position is less than certain. See Note 20—Income Taxes, for additional information about income tax-related contingencies.

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Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals

by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we

reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent

liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such

factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our

liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as

additional information becomes available during the administrative and litigation processes.

Environmental

We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record

accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base

liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business

considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’

cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our

determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state

sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs

related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other

financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned.

Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In

some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially

unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of

various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications

made by others for our benefit, and some of the indemnifications are subject to dollar limits and time limits.

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of

environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination,

which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these

costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional

environmental assessments, cleanups and proceedings. See Note 10—Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our

accrued environmental liabilities.

Legal Proceedings

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation

management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential

exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional

judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal

organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is

required.

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Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements.

Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput

capacity not utilized. In addition, at December 31, 2012, we had performance obligations secured by letters of credit of $852 million (issued as direct bank

letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of

business.

In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan

government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed

control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this

expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment

Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010, and we anticipate an interim decision on key legal

and factual issues in 2013. In a separate commercial arbitration from the Company’s ICSID claim discussed above, an International Chamber of Commerce

(ICC) tribunal issued a decision in favor of the Company in September 2012, finding PDVSA owed $67 million for pre-expropriation breaches of the

Petrozuata project agreements. In November 2012, based on the ICC tribunal ruling, PDVSA paid ConocoPhillips $68 million, including post-judgment

interest, which resulted in a $61 million after-tax earnings increase. The Company also recognized additional income of $173 million after-tax, associated with

the reversal of a related contingent liability accrual, which is recorded in the “Other income” line on our consolidated income statement.

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a

result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order

issued by ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally seized crude oil. In 2009, Ecuador took

over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation

claim. On April 24, 2012, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe are not material. The ICSID tribunal

issued a decision on liability on December 14, 2012, in favor of Burlington, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation

in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase will take place to determine the damages owed to ConocoPhillips

for Ecuador’s actions.

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax

assessments. Between 2010 and 2012, ConocoPhillips has paid, under protest, tax assessments totaling approximately $227 million, which are primarily

recorded in the “Investments and long-term receivables” line on our December 31, 2012, consolidated balance sheet. The arbitration will be conducted in

Singapore 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. The arbitration process is currently underway. Future impacts on our business are not known at this time.

Long-Term Throughput Agreements and Take-or-Pay Agreements

We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for natural gas or

crude oil transportation to be used in the ordinary course of the Company’s business. The aggregate amounts of estimated payments under these various

agreements are: 2013—$137 million; 2014—$136 million; 2015—$127 million; 2016—$28 million; 2017—$28 million; and 2018 and after—$158

million. Total payments under the agreements were $130 million in 2012, $429 million in 2011 and $216 million in 2010.

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Note 15—Derivative and Financial Instruments

We use futures, forwards, swaps and options in various markets to meet our customer needs and capture market opportunities. Our commodity business

primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids. Under our current business model, we are not required to register as a

Swap Dealer or Major Swap Participant.

Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented net. Related

cash flows are recorded as operating activities on the consolidated statement of cash flows. On the consolidated income statement, realized and unrealized gains

and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to

contracts that meet and are designated with the normal purchase normal sale exception are recognized upon settlement. We generally apply this exception to

eligible crude contracts. We do not use hedge accounting for our commodity derivatives.

The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they appear on our consolidated

balance sheet:

 

 Millions of Dollars 

 2012 2011 

Assets 

Prepaid expenses and other current assets $ 1,538 4,433 

Other assets 105 415 

Liabilities 

Other accruals 1,509 4,350 

Other liabilities and deferred credits 99 374 

The gains (losses) incurred from commodity derivatives, and the line items where they appear on our consolidated income statement were:

 

 Millions of Dollars 

 2012 2011 2010 

Sales and other operating revenues $ (291) 907 (964) 

Other income (1) (9) (5) 

Purchased commodities  214 (729) 915 

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts.

 

 Open Position 

Long/(Short)

 2012 2011 

Commodity 

Crude oil, refined products and natural gas liquids (millions of barrels) - (13) 

Natural gas and power (billions of cubic feet equivalent) 

Fixed price (48) (57) 

Basis 125 (25) 

Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily consists of

transactions designed to mitigate our cash-related and

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foreign currency exchange rate exposures, such as firm commitments for capital programs or local currency tax payments, dividends, and cash returns from

net investments in foreign affiliates. We do not elect hedge accounting on our foreign currency exchange derivatives.

The following table presents the gross fair values of our foreign currency exchange derivatives, excluding collateral, and the line items where they appear on

our consolidated balance sheet:

 

 Millions of Dollars 

 2012 2011 

Assets 

Prepaid expenses and other current assets $ 32 12 

Other assets - 1 

Liabilities 

Other accruals 2 23 

Other liabilities and deferred credits 1 - 

The (gains) losses from foreign currency exchange derivatives incurred, and the line items where they appear on our consolidated income statement were:

 

 Millions of Dollars 

 2012 2011 2010 

Foreign currency transaction (gains) losses $ (138) (9) 115 

We had the following net notional position of outstanding foreign currency exchange derivatives:

 

In Millions

 Notional Currency 

 2012 2011 

Foreign Currency Exchange Derivatives 

Sell U.S. dollar, buy other currencies* USD 2,573 1,949 

Sell euro, buy other currencies** EUR - 61 

Buy U.S. dollar, sell other currencies*** USD 140 - 

Buy euro, sell British pound EUR 96 - 

 *Primarilyeuro, Canadian dollar, Norwegian krone and British pound.

 **Primarily Norwegian krone and British pound.

***Primarily Canadian dollar, euro and Norwegian krone.

Financial Instruments

We invest excess cash in financial instruments with maturities based on our cash forecasts for the various currency pools we manage. The maturities of these

investments may from time to time extend beyond 90 days. The types of financial instruments include:

• Time deposits: Interest bearing deposits placed with approved financial institutions.

• Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank, or government agency purchased at a discount, maturing at

par.

These financial instruments appear in the “Cash and cash equivalents” line of our consolidated balance sheet if the maturities at the time we made the

investments were 90 days or less; otherwise, these held-to-maturity investments are included in the “Short-term investments” line. At December 31, we held the

following financial instruments:

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 Millions of Dollars

 Carrying Amount

 Cash and Cash Equivalents Short-Term Investments

 2012 2011 2012 2011 

Cash $ 829 1,169 - - 

Time Deposits 

Remaining maturities from 1 to 90 days 2,789 4,318 - 349 

Commercial Paper 

Remaining maturities from 1 to 90 days - 293 - 232 

 $ 3,618 5,780 - 581 

In conjunction with the separation of our Downstream business, we received a special cash distribution from Phillips 66 of $7,818 million. See Note 2

—Discontinued Operations, for additional information. At December 31, 2012, the unused amount of the special cash distribution was $748 million and is

designated as “Restricted cash” on our consolidated balance sheet. At December 31, 2012, the funds in the restricted cash account were invested in money

market funds with maturities within 90 days from December 31, 2012.

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, over-the-counter (OTC) derivative contracts

and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, money market funds, government debt

securities and time deposits with major international banks and financial institutions.

The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty

exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant

nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange

clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables

arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to

concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the

creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit,

prepayments, and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the

amounts owed by us or owed to others to be offset against amounts due us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have

contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold

amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment

grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral, such as transactions administered

through the New York Mercantile Exchange or IntercontinentalExchange.

The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were in a liability position on December 31, 2012,

was $130 million, for which no collateral was posted. If our credit rating were lowered one level from its “A” rating (per Standard and Poor’s) on December 31,

2012, we

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would be required to post no additional collateral to our counterparties. If we were downgraded below investment grade, we would be required to post $130

million of additional collateral, either with cash or letters of credit.

Note 16—Fair Value Measurement

We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell

an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:

• Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.

• Level 2: Inputs other than quoted prices that are directly or indirectly observable.

• Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are

subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market

data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer

available. Transfers occur at the end of the reporting period. There were no material transfers in or out of Level 1.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives and certain investments to support

nonqualified deferred compensation plans. The deferred compensation investments are measured at fair value using unadjusted prices available from national

securities exchanges; therefore, these assets are categorized as Level 1 in the fair value hierarchy. Level 1 derivative assets and liabilities primarily represent

exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 2 derivative assets and liabilities

primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers

or pricing service companies that are all corroborated by market data. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward

purchase and sale contracts that are long term in nature and where a significant portion of fair value is calculated from underlying market data that is not

readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled

market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value.

Level 3 activity was not material.

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The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity

derivatives accounted for at fair value on a recurring basis):

 Millions of Dollars

 December 31, 2012 December 31, 2011

 

 Level 1 Level 2 Level 3 Total  Level 1 Level 2 Level 3 Total

Assets 

Deferred compensation investments $ 305 - - 305 336 - - 336 

Commodity derivatives 1,052 567 18 1,637 2,807 1,947 72 4,826 

Total assets $ 1,357 567 18 1,942 3,143 1,947 72 5,162 

Liabilities 

Commodity derivatives $ 1,031 567 4 1,602 2,970 1,722 10 4,702 

Total liabilities $ 1,031 567 4 1,602 2,970 1,722 10 4,702 

Non-Recurring Fair Value Measurement

The following table summarizes the fair value hierarchy by major category for assets accounted for at fair value on a non-recurring basis:

 Millions of Dollars

 

Fair Value

Measurements Using 

 

 Fair Value* 

Level 1

Inputs 

Level 3

Inputs 

Before-Tax

Loss

Year ended December 31, 2012 

Net PP&E (held for sale) $ 6,116 6,116 - 798 

Net PP&E (held for use) 95 - 95 134 

Year ended December 31, 2011 

Net PP&E (held for use) ** $ 162 - 162 265 

Equity method investments *** 274 - 274 399 

Cost method investments 2 2 - 8 

 *Represents the fair value at the time of the impairment.

 **Before-tax loss includes $1 million related to discontinued operations.

***Before-tax loss includes $4 million related to discontinued operations.

2012

Net PP&E held for sale was written down to fair value, less costs to sell. The fair value of each asset was determined by its binding negotiated selling price.

Net PP&E held for use is comprised of various producing properties impaired to their individual fair values. The fair values were determined by the use of

internal discounted cash flow models using estimates of future production, prices from futures exchanges and pricing service companies, costs and a discount

rate believed to be consistent with those used by principal market participants.

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2011

During 2011, net PP&E held for use with a carrying amount of $427 million was written down to a fair value of $162 million, resulting in a before-tax loss

of $265 million. The fair values were determined by the use of internal discounted cash flow models using estimates of future production, prices, costs and a

discount rate believed to be consistent with those used by principal market participants and cash flow multiples for similar assets and alternative use.

Also during 2011, certain equity method investments were determined to have fair values below their carrying amount, and the impairments were considered to

be other than temporary. This primarily included an investment associated with our Other International segment with a book value of $651 million, which

was written down to its fair value of $256 million, resulting in a charge of $395 million before-tax. This was included in the “Equity in earnings of

affiliates” line of our consolidated income statement. The fair value was determined by the application of an internal discounted cash flow model using

estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants. In addition, the fair

value was determined by the comparison of market data for certain similar undeveloped properties.

Reported Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:

• Cash and cash equivalents, restricted cash and short-term investments: The carrying amount reported on the balance sheet approximates fair

value.

• Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair

value. The valuation technique and methods used to estimate the fair value of the current portion of fixed-rate related party loans is consistent with

Loans and advances—related parties.

• Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity

is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 6—Investments, Loans and LongTerm Receivables, for additional information.

• Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the

balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of the joint

venture acquisition obligation is consistent with the methodology below.

• Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market

data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.

• Joint venture acquisition obligation—related party: Fair value is estimated based on the net present value of the future cash flows as a Level 2 fair

value, discounted at December 31, 2012, and December 31, 2011, effective yield rates of 0.7 percent and 1.24 percent, respectively, based on

yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread and the amortizing nature of the

obligation principal. See Note 12—Joint Venture Acquisition Obligation, for additional information.

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The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):

 Millions of Dollars

 Carrying Amount Fair Value

 2012 2011 2012 2011

Financial assets 

Deferred compensation investments $ 305 336 305 336

Commodity derivatives 221 814 221 814

Total loans and advances—related parties 1,697 1,793 1,916 1,994

Financial liabilities 

Total debt, excluding capital leases 21,709 22,592 26,349 27,065

Total joint venture acquisition obligation 3,582 4,314 3,968 4,820

Commodity derivatives 199 446 199 446

At December 31, 2012, commodity derivative assets and liabilities appear net of $29 million of obligations to return cash collateral and $16 million of rights

to reclaim cash collateral, respectively. At December 31, 2011, commodity derivative assets and liabilities appear net of no obligations to return cash collateral

and $244 million of rights to reclaim cash collateral.

Note 17—Equity

Common Stock

The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:

 Shares

 2012 2011 2010

Issued 

Beginning of year 1,749,550,587 1,740,529,279 1,733,345,558 

Distributed under benefit plans 12,697,362 9,021,308 7,183,721 

End of year 1,762,247,949 1,749,550,587 1,740,529,279 

Held in Treasury 

Beginning of year 463,880,628 272,873,537 208,346,815 

Repurchase of common stock 79,904,400 155,453,382 64,526,722 

Distributed under benefit plans (1,554,355) (475,696) - 

Transfer from grantor trust - 36,029,405 - 

End of year 542,230,673 463,880,628 272,873,537 

Held in Grantor Trusts 

Beginning of year - 36,890,375 38,742,261 

Repurchase of common stock - (157,470) - 

Distributed under benefit plans - (703,500) (1,776,873) 

Transfer to treasury stock - (36,029,405) - 

Other - - (75,013) 

End of year - - 36,890,375 

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Preferred Stock

We have authorized 500 million shares of preferred stock, par value $.01 per share, none of which was issued or outstanding at December 31, 2012 or 2011.

Noncontrolling Interests

At December 31, 2012 and 2011, we had outstanding $440 million and $510 million, respectively, of equity in less-than-wholly owned consolidated

subsidiaries held by noncontrolling interest owners. At December 31, 2012, the entire amount was related to Darwin LNG, an operating joint venture we

control, located in Australia’s Northern Territory. At December 31, 2011, $482 million was related to Darwin LNG and $28 million was related to

discontinued operations.

Note 18—Non-Mineral Leases

The company leases ocean transport vessels, tugboats, barges, corporate aircraft, drilling equipment, computers, office buildings and other facilities and

equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options

to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions imposed on us by the leasing

agreements with regard to dividends, asset dispositions or borrowing ability. Leased assets under capital leases were not significant in any period presented.

At December 31, 2012, future minimum rental payments due under noncancelable leases were:

 

Millions

of Dollars

 2013 

 $ 477 

 2014 580 

 2015 380 

 2016 314 

 2017 110 

 Remaining years 290 

 Total 2,151 

 Less income from subleases 24 

 Net minimum operating lease payments  $ 2,127 

Operating lease rental expense for the years ended December 31 was:

 Millions of Dollars

 2012 2011 2010

Total rentals* $ 282 304 267 

Less sublease rentals (15) (14) (14) 

 $ 267 290 253 

*Includes $3 million, $29 million and $16 million of contingent rentals in 2012, 2011 and 2010, respectively. Contingent rentals primarily are related to drilling equipment and are

based on usage or volume of product sold.

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Note 19—Employee Benefit Plans

Pension and Postretirement Plans

In connection with the separation of the Downstream business, ConocoPhillips entered into an Employee Matters Agreement with Phillips 66, see Note 2

—Discontinued Operations, which provides that employees of Phillips 66 no longer participate in benefit plans sponsored or maintained by ConocoPhillips

as of the separation date. Upon separation, the ConocoPhillips pension and postretirement plans transferred assets and obligations to the Phillips 66 plans

resulting in a net decrease in sponsored pension and postretirement plan obligations of $1,127 million. Additionally, as a result of the transfer of unrecognized

losses to Phillips 66, deferred income taxes and other comprehensive income decreased $335 million and $570 million, respectively.

An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance

plans follows:

 Millions of Dollars

 Pension Benefits Other Benefits

 2012 2011 2012 2011

 U.S. Int’l. U.S. Int’l.

Change in Benefit Obligation 

Benefit obligation at January 1 $ 6,175 3,484 5,539 3,206 926 862 

Service cost 170 91 225 98 6 10 

Interest cost 186 152 247 178 33 42 

Plan participant contributions - 7 - 5 23 23 

Government subsidy - - - - - 4 

Separation of Downstream business (2,464) (653) - - (199) - 

Plan amendments - - - (53) - 35 

Actuarial loss 735 297 642 195 47 20 

Benefits paid (577) (113) (478) (116) (72) (68) 

Foreign currency exchange rate change - 173 - (29) 1 (2) 

Benefit obligation at December 31* $ 4,225 3,438 6,175 3,484 765 926 

*Accumulated benefit obligation portion of above at

December 31: $ 3,710 2,972 5,363 2,939

Change in Fair Value of Plan Assets 

Fair value of plan assets at January 1 $ 4,149 2,722 3,890 2,581 - - 

Actual return on plan assets 509 267 64 53 - - 

Company contributions 363 204 673 226 49 41 

Plan participant contributions - 7 - 5 23 23 

Government subsidy - - - - - 4 

Separation of Downstream business (1,712) (479) - - - - 

Benefits paid (577) (113) (478) (116) (72) (68) 

Foreign currency exchange rate change - 152 - (27) - - 

Fair value of plan assets at December 31 $ 2,732 2,760 4,149 2,722 - - 

Funded Status $ (1,493) (678) (2,026) (762) (765) (926) 

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 Millions of Dollars

 Pension Benefits Other Benefits

 2012 2011 2012 2011

 U.S. Int’l. U.S. Int’l. 

Amounts Recognized in the

Consolidated Balance Sheet at

December 31 

Noncurrent assets $ - 94 - 94 - - 

Current liabilities (21) (8) (118) (5) (54) (62) 

Noncurrent liabilities (1,472) (764) (1,908) (851) (711) (864) 

Total recognized $ (1,493) (678) (2,026) (762) (765) (926) 

Weighted-Average Assumptions Used to

Determine Benefit Obligations at

December 31 

Discount rate 3.55 % 4.50 4.30 4.90 3.55 4.40 

Rate of compensation increase 4.75 4.45 4.25 4.30 - - 

Weighted-Average Assumptions Used to

Determine Net Periodic Benefit Cost for

Years Ended December 31 

Discount rate 4.00 % 4.95 4.65 5.40 4.25 5.00 

Expected return on plan assets 7.00 6.10 7.00 6.40 - - 

Rate of compensation increase 4.50 4.50 4.00 4.10 - - 

For both U.S. and international pensions, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted

by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for

each class of assets.

Included in accumulated other comprehensive income at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit

cost:

 Millions of Dollars

 Pension Benefits Other Benefits

 2012 2011 2012 2011

 U.S. Int’l. U.S. Int’l.

Unrecognized net actuarial loss (gain) $ 1,509 758 2,240 705 29 (26) 

Unrecognized prior service cost (credit) 28 (60) 52 (78) (12) (13) 

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 Millions of Dollars

 Pension Benefits Other Benefits

 2012 2011 2012 2011

 

 U.S. Int’l. U.S. Int’l.

Sources of Change in Other

Comprehensive Income 

Net loss arising during the period $ (450) (206) (858) (307) (48) (20) 

Separation of Downstream business  810 94 - - (7) - 

Amortization of (gain) loss included in income* 371 59 185 46 - (5) 

Net change during the period $ 731 (53) (673) (261) (55) (25) 

Prior service (cost) credit arising during the period $ - 2 - 53 - (34) 

Separation of Downstream business 17 (12) - - 3 - 

Amortization of prior service cost (credit) included in income 7 (8) 9 - (4) (7) 

Net change during the period $ 24 (18) 9 53 (1) (41) 

* Includes settlement losses recognized during the period.

Amounts included in accumulated other comprehensive income at December 31, 2012, that are expected to be amortized into net periodic postretirement cost

during 2013 are provided below:

 Millions of Dollars

 Pension Benefits Other Benefits

 U.S. Int’l. 

Unrecognized net actuarial loss $ 151 76 3

Unrecognized prior service cost (credit) 6 (8) (4) 

For our tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected benefit obligation, the accumulated benefit

obligation, and the fair value of plan assets were $6,278 million, $5,602 million, and $4,537 million, respectively, at December 31, 2012, and $8,481

million, $7,377 million, and $6,098 million, respectively, at December 31, 2011.

For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $525

million and $382 million, respectively, at December 31, 2012, and were $499 million and $374 million, respectively, at December 31, 2011.

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The components of net periodic benefit cost of all defined benefit plans are presented in the following table:

 Millions of Dollars

 Pension Benefits Other Benefits

 2012 2011 2010 2012 2011 2010

 U.S. Int’l. U.S. Int’l. U.S. Int’l.

Components of Net

Periodic Benefit Cost 

Service cost $ 170 91 225 98 229 90 6 10 11 

Interest cost  186 152 247 178 260 169 33 42 46 

Expected return on plan assets (223) (158) (280) (175) (224) (147) - - - 

Amortization of prior service cost (credit) 7 (8) 9 - 10 2 (4) (7) 3 

Recognized net actuarial loss (gain) 191 59 165 46 167 5 5 - (5) (7) 

Net periodic benefit cost $ 331 136 366 147 442 169 35 40 53 

In addition to the above, we recognized pension settlement losses of $181 million (including $24 million in discontinued operations) in 2012 and $21 million

in 2011. None was recognized in 2010. In 2012, lump-sum benefit payments from the U.S. qualified pension plan exceeded the sum of service and interest

costs for that plan and led to an increase in settlement losses.

In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service

period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year.

We have multiple nonpension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost

sharing features, with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the

accumulated postretirement benefit obligation assumes a health care cost trend rate of 7.5 percent in 2012 that declines to 5 percent by 2023. A one-percentagepoint change in the assumed health care cost trend rate would be immaterial to ConocoPhillips.

Plan Assets—We follow a policy of broadly diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a

result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include U.S. equities, non-U.S. equities,

U.S. fixed income, non-U.S. fixed income, real estate and private equity investments. Plan fiduciaries may consider and add other asset classes to the

investment program from time to time. The target allocations for plan assets are 59 percent equity securities, 37 percent debt securities and 4 percent real estate.

Generally, the plan investments are publicly traded, therefore minimizing liquidity risk in the portfolio.

The following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at

December 31, 2012 and 2011.

• Fair values of equity securities and government debt securities categorized in Level 1 are primarily based on quoted market prices.

• Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 are estimated

using recently executed transactions and quoted market prices. If there have been no market transactions in a particular fixed income security, its

fair value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable quoted

market prices are not available, fair value is based on

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pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades and issuer

spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy.

• Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets.

• Fair values of mutual funds are based on quoted market prices, which represent the net asset value of shares held.

• Cash is valued at cost, which approximates fair value. Fair values of international cash equivalents categorized in Level 2 are valued using

observable yield curves, discounting and interest rates. U.S. cash balances held in the form of short-term fund units that are redeemable at the

measurement date are categorized as Level 2.

• Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For other derivatives classified in Level 2, the

values are generally calculated from pricing models with market input parameters from third-party sources.

• Private equity funds are valued at net asset value as determined by the issuer based on the fair value of the underlying assets.

• Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the plans’

participants.

• Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party

sources and sales comparables where available.

• A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity contract, which is calculated as the market value

of investments held under this contract, less the accumulated benefit obligation covered by the contract. The participating interest is classified as

Level 3 in the fair value hierarchy, as the fair value is determined via a combination of quoted market prices, recently executed transactions, and

an actuarial present value computation for contract obligations. At December 31, 2012, the participating interest in the annuity contract was

valued at $133 million and consisted of $358 million in debt securities, less $225 million for the accumulated benefit obligation covered by the

contract. At December 31, 2011, the participating interest in the annuity contract was valued at $144 million and consisted of $391 million in

debt securities, less $247 million for the accumulated benefit obligation covered by the contract. The net change from 2011 to 2012 is due to a

decrease in the fair value of the underlying investments of $33 million and a decrease in the present value of the contract obligation of $22 million.

The participating interest is not available for meeting general pension benefit obligations in the near term. No future company contributions are

required and no new benefits are being accrued under this insurance annuity contract.

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The fair values of our pension plan assets at December 31, by asset class were as follows:

 Millions of Dollars

 U.S. International

 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total

2012 

Equity Securities 

U.S. $ 875 - - 875 443 - - 443 

International 587 - - 587 381 - - 381 

Common/collective trusts - 472 - 472 - 195 - 195 

Mutual funds - - - - 319 - - 319 

Debt Securities 

Government 146 54 - 200 496 - - 496 

Corporate - 306 2 308 - 155 1 156 

Agency and mortgage-backed securities - 59 - 59 - 29 - 29 

Common/collective trusts - - - - - 314 - 314 

Mutual funds - - - - 155 - - 155 

Cash and cash equivalents - 94 - 94 22 18 - 40 

Private equity funds - - 4 4 - - 18 18 

Derivatives - 1 - 1 10 13 - 23 

Real estate - - - - - - 183 183 

Total* $ 1,608 986 6 2,600 1,826 724 202 2,752 

* Excludes the participating interest in the insurance annuity contract with a net asset value of $133 million and net receivables related to security transactions of $7 million. 

2011 

Equity Securities 

U.S. $1,251 - - 1,251 413 - - 413 

International 803 - - 803 413 - - 413 

Common/collective trusts - 634 - 634 - 234 - 234 

Mutual funds - - - - 246 - - 246 

Debt Securities 

Government 311 81 - 392 532 - - 532 

Corporate - 551 3 554 - 122 1 123 

Agency and mortgage-backed securities - 105 - 105 - 43 - 43 

Common/collective trusts - - - - - 346 - 346 

Mutual funds - - - - 130 - - 130 

Cash and cash equivalents - 249 - 249 32 26 - 58 

Private equity funds - - 4 4 - - 13 13 

Derivatives - - - - - 11 - 11 

Insurance contracts - - - - - - 15 15 

Real estate - - - - - - 139 139 

Total* $2,365 1,620 7 3,992 1,766 782 168 2,716 

*Excludes the participating interest in the insurance annuity contract with a net asset value of $144 million and net receivables related to security transactions of $19 million.

Level 3 activity was not material.

Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal

Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2013, we expect to contribute

approximately $275

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million to our domestic qualified and nonqualified pension and postretirement benefit plans and $210 million to our international qualified and nonqualified

pension and postretirement benefit plans.

The following benefit payments, which are exclusive of amounts to be paid from the insurance annuity contract and which reflect expected future service, as

appropriate, are expected to be paid:

 Millions of Dollars

 Pension Benefits 

 Other Benefits

 U.S. Int’l. 

2013 $ 375 118 62

2014 370 126 63

2015 366 137 63

2016 370 141 63

2017 399 146 63

2018-2022 2,067 897 291

Defined Contribution Plans

Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can deposit up to 75 percent of their eligible pay up to

the statutory limit ($17,000 in 2012) in the thrift feature of the CPSP to a choice of approximately 38 investment funds. Through 2012, ConocoPhillips

matched contribution deposits, up to 1.25 percent of eligible pay. Company contributions charged to expense related to continuing and discontinued operations

for the CPSP and predecessor plans, excluding the stock savings feature (discussed below), were $16 million in 2012, $25 million in 2011, and $24 million

in 2010.

The stock savings feature of the CPSP is a leveraged employee stock ownership plan. Through 2012, employees could elect to participate in the stock savings

feature by contributing 1 percent of eligible pay and receiving an allocation of shares of common stock proportionate to the amount of contribution.

In 1990, the Long-Term Stock Savings Plan of Phillips Petroleum Company (now the stock savings feature of the CPSP) borrowed funds that were used to

purchase previously unissued shares of company common stock. Since the Company guarantees the CPSP’s borrowings, the unpaid balance is reported as a

liability of the Company and unearned compensation is shown as a reduction of common stockholders’ equity. Dividends on all shares are charged against

retained earnings. The debt is serviced by the CPSP from company contributions and dividends received on certain shares of common stock held by the plan,

including all unallocated shares. The shares held by the stock savings feature of the CPSP are released for allocation to participant accounts based on debt

service payments on CPSP borrowings. In 2012, the final debt service payment was made and all remaining unallocated shares were released for allocation to

participant accounts.

We recognize interest expense as incurred and compensation expense based on the fair value of the stock contributed or on the cost of the unallocated shares

released, using the shares-allocated method. We recognized total CPSP expense related to continuing and discontinued operations to the stock savings feature of

$104 million, $77 million and $92 million in 2012, 2011 and 2010, respectively, all of which was compensation expense. In 2012 and 2011, we made cash

contributions to the CPSP of $5 million and $4 million, respectively. No cash contributions were made in 2010. In 2011 and 2010, we contributed 660,755

shares and 1,776,873 shares, respectively, of company common stock from the Compensation and Benefits Trust. The shares had a fair value of $84

million and $103 million, respectively. In 2012 and 2011, we contributed 1,554,355 and 475,696 shares, respectively, of company common stock from

treasury stock. Dividends used to service debt were $10 million, $45 million and $41 million in 2012, 2011 and 2010, respectively. These dividends reduced

the amount of compensation expense recognized each period. Interest incurred on the CPSP debt in 2012, 2011 and 2010 was $0.1 million, $1 million and

$2 million, respectively.

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The total CPSP stock savings feature shares as of December 31 were:

 2012 2011

Unallocated shares - 811,963 

Allocated shares 11,246,660 19,315,372 

Total shares 11,246,660 20,127,335 

The fair value of unallocated shares at December 31, 2011 was $59 million.

Starting in 2013, employees who participate in the CPSP and contribute 1 percent of their eligible pay will receive a 9 percent company cash match. CPSP will

no longer have a stock savings feature.

We have several defined contribution plans for our international employees, each with its own terms and eligibility depending on location. Total compensation

expense related to continuing and discontinued operations recognized for these international plans was approximately $56 million in 2012 and 2011 and

$52 million in 2010.

Share-Based Compensation Plans

The 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by shareholders in May 2011. Over its 10-year life, the

Plan allows the issuance of up to 100 million shares of our common stock for compensation to our employees and directors; however, as of the effective date of

the Plan, (i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common stock represented by awards

granted under the prior plans that are forfeited, expire or are canceled without delivery of shares of common stock or which result in the forfeiture of shares of

common stock back to the company shall be available for awards under the Plan, and no new awards shall be granted under the prior plans. Of the

100 million shares available for issuance under the Plan, no more than 40 million shares of common stock are available for incentive stock options, and no

more than 40 million shares are available for awards in stock.

Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for

awards held by employees at the time of their retirement. We recognize share-based compensation expense over the shorter of the service period (i.e., the stated

period of time required to earn the award); or the period beginning at the start of the service period and ending when an employee first becomes eligible for

retirement, but not less than six months, as this is the minimum period of time required for an award to not be subject to forfeiture. Some of our share-based

awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). We

recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

Separation-Related Adjustments—In connection with the separation of the Downstream business on April 30, 2012, ConocoPhillips entered into an

Employee Matters Agreement with Phillips 66, see Note 2— Discontinued Operations, which provides that employees of Phillips 66 no longer participate in

benefit plans sponsored or maintained by ConocoPhillips. Pursuant to the Employee Matters Agreement, we made certain adjustments, using volumetric

weighted-average prices for the 4-day period immediately prior to and immediately following the separation, to the exercise price and number of our share-based

compensation awards, with the intention of preserving the intrinsic value of the awards immediately prior to the separation. These adjustments are

summarized as follows and are reflected in the activity tables below:

• Outstanding options to purchase common shares of ConocoPhillips stock that were exercisable prior to the separation were adjusted so that the

holders of the options would then hold one option to purchase common shares of Phillips 66 stock for every two adjusted stock options to

purchase common shares of ConocoPhillips stock following the separation.

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• Nonexercisable stock options and restricted stock units were converted to those of the entity where the employee holding them is working

immediately post-separation. Therefore, nonexercisable stock options to purchase common shares of ConocoPhillips stock and ConocoPhillips

restricted stock units held by an employee who separated with the Downstream business were surrendered as a result of the separation.

• In addition, former employee holders and a specified group of holders of stock options and restricted stock units who retired or terminated

employment upon or shortly after the separation received both adjusted ConocoPhillips awards and Philips 66 awards.

• ConocoPhillips restricted stock and performance share units awarded for completed performance periods under the Performance Share Program,

as well as vested restricted stock units held by current or former directors, were adjusted to provide holders one restricted share or restricted stock

unit of Phillips 66 stock for every two restricted shares or restricted stock units of ConocoPhillips stock.

The separation-related adjustments did not have a material impact on either compensation expense or the potentially dilutive securities to be considered in the

calculation of diluted earnings per share of common stock.

Compensation Expense—Total share-based compensation expense recognized in income related to continuing and discontinued operations and the associated

tax benefit for the years ended December 31 were as follows:

 Millions of Dollars

 2012 2011 2010

Compensation cost $ 321 246 211 

Tax benefit 118 86 78 

Stock Options—Stock options granted under the provisions of the Plan and prior plans permit purchase of our common stock at exercise prices equivalent to

the average market price of the stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the

options awarded vesting and becoming exercisable on each anniversary date following the date of grant. Options awarded to certain employees already eligible

for retirement vest within 6 months of the grant date, but those options do not become exercisable until the end of the normal vesting period.

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The following summarizes our stock option activity for the year ended December 31, 2012:

 WeightedWeightedAverage 

 Millions of Dollars

 Options

Average

 Exercise Price 

 Grant-Date

Fair Value 

Aggregate

Intrinsic Value

Outstanding at December 31, 2011 24,372,051 $ 45.73 

Granted 2,335,600 71.87  $ 15.69 

Exercised (9,735,269) 25.34  $ 469 

Forfeited (462,862) 55.76 

Expired or canceled (32,048) 65.65 

Options surrendered, as a result of the separation (1,045,820) 68.01 

Options granted in conversion, as a result of the separation 865,353 45.92 

Outstanding at December 31, 2012 16,297,005 $ 43.67 

Vested at December 31, 2012 14,348,278 $ 42.58  $ 219 

Exercisable at December 31, 2012 12,725,857 $ 41.90  $ 204 

The weighted-average remaining contractual term of vested options and exercisable options at December 31, 2012, was 4.92 years and 4.52 years, respectively.

The weighted-average grant date fair value of stock option awards granted during 2011 and 2010 was $16.70 and $11.70, respectively. The aggregate intrinsic

value of options exercised during 2011 and 2010 was $416 million and $183 million, respectively.

During 2012, we received $294 million in cash and realized a tax benefit related to continuing and discontinued operations of $153 million from the exercise

of options. At December 31, 2012, the remaining unrecognized compensation expense from unvested options was $9 million, which will be recognized over a

weighted-average period of 1.66 years, the longest period being 2.11 years.

The fair market values of the options granted over the past three years were measured on the date of grant using the Black-Scholes option-pricing model.

During 2012, all stock option grants occurred prior to the separation of the Downstream business. The weighted-average assumptions used were as follows:

 

 2012 2011 2010 

Assumptions used 

Risk-free interest rate 1.62 % 3.10 3.23 

Dividend yield 4.00 % 4.00 4.00 

Volatility factor 33.30 % 33.40 33.80 

Expected life (years) 7.42 6.87 6.65 

The ranges in the assumptions used were as follows:

 2012 2011 2010

 High Low High Low High Low 

Ranges used 

Risk-free interest rate 1.62 % 1.62 3.10 3.10 3.23 3.23 

Dividend yield 4.00 4.00 4.00 4.00 4.00 4.00 

Volatility factor 33.30 33.30 33.40 33.40 33.80 33.80 

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Expected volatility above was based on historical volatility of the company’s stock using ConocoPhillips end-of-week closing stock prices over a period

commensurate with the expected life of the options granted. We periodically calculate the average period of time lapsed between grant dates and exercise dates of

past grants to estimate the expected life of new option grants. Due to the separation of our Downstream business, our calculation of expected volatility for grants

of options in 2013 will be based on a three-year average historical stock price volatility of a group of peer companies.

Stock Unit Program—Generally, restricted stock units are granted annually under the provisions of the Plan and vest ratably, with one-third of the units

vesting in 36 months, one-third vesting in 48 months, and the final third vesting 60 months from the date of grant. Beginning with restricted stock units

granted in 2013, the general vesting schedule will accelerate with units vesting 36 months from the date of grant. In addition, beginning in 2012, restricted

stock units are granted under the Plan for a variable long-term incentive program, with one-third of units vesting in 12 months, one-third vesting in 24

months, and the final one-third vesting 36 months from the date of grant. Restricted stock units are also granted ad hoc to attract or retain key personnel, and

the terms and conditions under which these restricted stock units vest vary by award. Upon vesting, the units are settled by issuing one share of

ConocoPhillips common stock per unit. Units awarded to certain employees already eligible for retirement vest six months from the grant date, but those units

are not issued as shares until the end of the normal vesting period. Until issued as stock, most recipients of the units receive a quarterly cash payment of a

dividend equivalent that is charged to retained earnings. The grant date fair value of these units is deemed equal to the average ConocoPhillips stock price on

the date of grant. The grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal to the average

ConocoPhillips stock price on the grant date, less the net present value of the dividends that will not be received.

The following summarizes our stock unit activity for the year ended December 31, 2012:

 Weighted-Average Millions of Dollars

 

 Stock Units Grant-Date Fair Value Total Fair Value

Outstanding at December 31, 2011 8,728,958 $ 55.41

Granted 5,911,369 60.62

Forfeited (319,691) 52.70

Issued (2,755,134) $ 187 

Awards surrendered, as a result of the separation (2,368,520) 59.56

Awards granted in conversion, as a result of the separation 2,280,140 45.00

Outstanding at December 31, 2012 11,477,122 $ 46.58

Not Vested at December 31, 2012 8,659,344 $ 47.63

At December 31, 2012, the remaining unrecognized compensation cost from the unvested units was $279 million, which will be recognized over a weightedaverage period of 2.54 years, the longest period being 7.34 years. The weighted-average grant date fair value of stock unit awards granted during 2011 and

2010 was $67.54 and $46.38, respectively. The total fair value of stock units issued during 2011 and 2010 was $109 million and $79 million, respectively.

Performance Share Program—Under the Plan, we also annually grant to senior management restricted performance share units (PSUs) that do not vest

until either (i) with respect to awards for performance periods beginning before 2009, the employee becomes eligible for retirement by reaching age 55 with five

years of service or (ii) with respect to awards for performance periods beginning in 2009, five years after the grant date of the award (although recipients can

elect to defer the lapsing of restrictions until retirement after reaching age 55 with five years of service), so we recognize compensation expense for these awards

beginning on the date of grant and ending on the date the PSUs are scheduled to vest. Since these awards are authorized three years prior to the grant date, for

employees eligible for such retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of

authorization and ending on the date of grant. These PSUs are settled by issuing one share of ConocoPhillips common stock per unit. Until issued

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as stock, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent that is charged to retained earnings. In its current form, the first

grant of PSUs under this program was in 2006.

During 2012, performance share awards previously authorized but not yet granted prior to the separation with our Downstream business were granted and a

pro-rata number of performance share stock units were awarded to the employee participants.

The following summarizes our Performance Share Program activity for the year ended December 31, 2012:

 Weighted-Average 

 Millions of Dollars

 

 Stock Units Grant-Date Fair Value  Total Fair Value

Outstanding at December 31, 2011 3,517,761 $ 64.35 

Granted 2,812,828 74.16 

Forfeited (4,893) 63.18 

Issued (1,141,412)  $ 71 

Outstanding at December 31, 2012 5,184,284 $ 51.54 

Not Vested at December 31, 2012 1,628,706 $ 52.79 

At December 31, 2012, the remaining unrecognized compensation cost from unvested performance share awards was $45 million, which includes $11

million related to unvested performance share awards tied to Phillips 66 stock held by ConocoPhillips employees, which will be recognized over a weightedaverage period of 3.83 years, the longest period being 8.19 years. The weighted-average grant date fair value of performance share units granted during 2011

and 2010 was $70.57 and $48.39, respectively. The total fair value of performance share units issued during 2011 and 2010 was $37 million and $12

million, respectively.

Other—In addition to the above active programs, we have outstanding shares of restricted stock and restricted stock units that were either issued to replace

awards held by employees of companies we acquired or issued as part of a compensation program that has been discontinued. Generally, the recipients of the

restricted shares or units receive a quarterly dividend or dividend equivalent.

The following summarizes the aggregate activity of these restricted shares and units for the year ended December 31, 2012:

 Weighted-Average 

 Millions of Dollars

 

 Stock Units Grant-Date Fair Value  Total Fair Value

Outstanding at December 31, 2011 2,587,915 $ 33.49 

Granted 86,701 63.54 

Forfeited (205,701) 24.20 

Issued (1,336,359)  $ 73 

Outstanding at December 31, 2012 1,132,556 $ 27.34 

Not Vested at December 31, 2012 - 

At December 31, 2012, all outstanding restricted stock and restricted stock units were fully vested and there was no remaining compensation cost to be

recorded. The weighted-average grant date fair value of restricted shares and units granted during 2011 and 2010 was $70.25 and $53.33, respectively. The

total fair value of restricted shares and units issued during 2011 and 2010 was $10 million and $9 million, respectively.

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Note 20—Income Tax

Income taxes charged to income from continuing operations were:

 Millions of Dollars

 2012 2011 2010 

Income Taxes 

Federal 

Current $ 63 1,066 1,231 

Deferred 624 285 148 

Foreign 

Current 6,255 6,400 7,050 

Deferred 744 48 (1,120) 

State and local 

Current 231 308 255 

Deferred 25 101 6 

 $ 7,942 8,208 7,570 

Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes

and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:

 

 Millions of Dollars 

 2012 2011 

Deferred Tax Liabilities 

PP&E and intangibles $ 18,826 21,159 

Investment in joint ventures 872 2,943 

Inventory 76 - 

Partnership income deferral 343 363 

Other 793 703 

Total deferred tax liabilities 20,910 25,168 

Deferred Tax Assets 

Benefit plan accruals 1,760 2,063 

Asset retirement obligations and accrued environmental costs 3,954 4,254 

Inventory - 43 

Deferred state income tax 77 299 

Other financial accruals and deferrals 544 618 

Loss and credit carryforwards 2,062 1,608 

Other 398 692 

Total deferred tax assets 8,795 9,577 

Less valuation allowance (1,345) (1,487) 

Net deferred tax assets 7,450 8,090 

Net deferred tax liabilities $ 13,460 17,078 

Current assets, long-term assets, current liabilities and long-term liabilities included deferred taxes of $461 million, $222 million, $958 million and

$13,185 million, respectively, at December 31, 2012, and $788 million, $183 million, $9 million and $18,040 million, respectively, at December 31, 2011.

The reduction in net deferred tax liabilities from 2011 to 2012 was primarily due to the separation of our Downstream business. See Note 2—Discontinued

Operations for more information.

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We have loss and credit carryovers in multiple taxing jurisdictions. These attributes generally expire between 2013 and 2032 with some carryovers having

indefinite carryforward periods.

Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2012, valuation

allowances decreased a total of $142 million. This reflects decreases of $516 million primarily related to the separation of our Downstream business, asset

relinquishment and utilization of loss carryforwards, partially offset by increases of $374 million, primarily related to U.S. foreign tax credit and foreign and

state loss carryforwards. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects

remaining net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as offsets to the tax consequences of future taxable income.

At December 31, 2012 and 2011, income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled

approximately $2,286 million and $4,227 million, respectively. Deferred income taxes have not been provided on this income, as we do not plan to initiate

any action that would require the payment of income taxes. It is not practicable to estimate the amount of additional tax that might be payable on this foreign

income if distributed.

The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2012, 2011 and 2010:

 Millions of Dollars

 

 2012 2011 2010 

Balance at January 1  $ 1,071 1,125 1,208 

Additions based on tax positions related to the current year 98 46 63 

Additions for tax positions of prior years 48 145 344 

Reductions for tax positions of prior years (206) (35) (199) 

Settlements (108) (206) (215) 

Lapse of statute (31) (4) (76) 

Balance at December 31  $ 872 1,071 1,125 

Included in the balance of unrecognized tax benefits for 2012, 2011 and 2010 were $650 million, $815 million and $914 million, respectively, which, if

recognized, would impact our effective tax rate.

At December 31, 2012, 2011 and 2010, accrued liabilities for interest and penalties totaled $129 million, $141 million and $171 million, respectively, net of

accrued income taxes. Interest and penalties resulted in a benefit to earnings in 2012 of $9 million, a charge to earnings in 2011 of $10 million, and a benefit

to earnings in 2010 of $2 million.

We and our subsidiaries file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions are generally

complete as follows: United Kingdom (2009), Canada (2005), United States (2008) and Norway (2011). Issues in dispute for audited years and audits for

subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world. As a consequence, the

balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible such changes could be significant when

compared with our total unrecognized tax benefits, but the amount of change is not estimable.

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The amounts of U.S. and foreign income from continuing income before income taxes, with a reconciliation of tax at the federal statutory rate with the

provision for income taxes, were:

 Millions of Dollars

Percent of

Pretax Income

 2012 2011 2010 2012 2011 2010 

Income before income taxes from continuing operations

United States $ 4,070 4,762 3,872 26.4% 30.9 21.7

Foreign 11,353 10,634 14,003 73.6 69.1 78.3

 $ 15,423 15,396 17,875 100.0% 100.0 100.0

Federal statutory income tax $ 5,398 5,389 6,256 35.0% 35.0 35.0

Foreign taxes in excess of federal statutory rate 2,878 2,658 1,238 18.6 17.3 6.9

Capital loss benefit (461) - - (3.0) - -

Federal manufacturing deduction (52) (73) (75) (0.3) (0.5) (0.4) 

State income tax 166 266 170 1.1 1.7 0.9

Other 13 (32) (19) 0.1 (0.2) (0.1) 

 $ 7,942 8,208 7,570 51.5% 53.3 42.3

The change in the effective tax rate from 2011 to 2012 was primarily due to the effect of the Company’s asset disposition program, partially offset by higher

income in high tax jurisdictions in 2012. The change in the effective tax rate from 2010 to 2011 was primarily due to tax benefits associated with asset

dispositions occurring in 2010.

In the United Kingdom, legislation was enacted on July 17, 2012, restricting corporate tax relief on decommissioning costs to 50 percent, retroactively effective

from March 21, 2012. Our 2012 earnings were reduced by $192 million due to remeasurement of deferred tax balances as of the effective date.

In the United Kingdom, legislation was enacted on July 19, 2011, which increased the supplementary corporate tax rate applicable to U.K. Upstream activity

from 20 to 32 percent, retroactively effective from March 24, 2011. This resulted in the overall U.K. corporate rate increasing from 50 percent to 62 percent.

The enactment resulted in increased U.K. corporate income tax expense of $316 million in 2011. This is comprised of $106 million due to remeasurement of

U.K. deferred tax liabilities, and $210 million to reflect the new rate from March 24, 2011, through December 31, 2011.

Statutory tax rate changes did not have a significant impact on our income tax expense in 2010.

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Note 21—Accumulated Other Comprehensive Income

Accumulated other comprehensive income in the equity section of the balance sheet included:

 Millions of Dollars

 

Defined

Benefit Plans

Net

Unrealized

Gain on

Securities

Foreign

Currency

Translation Hedging

Accumulated

Other

Comprehensive

Income (Loss)

December 31, 2009 $ (1,504) - 4,736 (7) 3,225 

Other comprehensive income 146 158 1,404 - 1,708 

December 31, 2010 (1,358) 158 6,140 (7) 4,933 

Other comprehensive income (loss) (613) (158) (917) 1 (1,687) 

December 31, 2011 (1,971) - 5,223 (6) 3,246 

Other comprehensive income (loss) (137) - 758 6 627 

Separation of Downstream business 683 - (469) - 214 

December 31, 2012 $ (1,425) - 5,512 - 4,087 

Note 22—Cash Flow Information

Amounts included in continuing operations for the years ended December 31 were:

 Millions of Dollars

 

 2012 2011 2010 

Noncash Investing and Financing Activities 

Increase in PP&E related to an increase in asset retirement obligations $ 1,010* 182 808 

Cash Payments 

Interest $ 724 919 1,120 

Income taxes 8,568 10,285 8,262 

Net Sales (Purchases) of Short-Term Investments 

Short-term investments purchased $ (497) (6,744) (982) 

Short-term investments sold 1,094 7,144 -

 $ 597 400 (982) 

*Includes$152 million primarily related to U.K. tax law changes on the deductibility of decommissioning costs.

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Note 23—Other Financial Information

Amounts included in continuing operations for the years ended December 31 were:

 

Millions of Dollars

 Except Per Share Amounts 

 2012 2011 2010 

Interest and Debt Expense 

Incurred 

Debt $ 1,170 1,230 1,401 

Other 154 212 237 

 1,324 1,442 1,638 

Capitalized (615) (488) (471) 

Expensed $ 709 954 1,167 

Other Income 

Interest income $ 163 170 135 

Other, net 306 94 46 

 $ 469 264 181 

Research and Development Expenditures—expensed $ 221 193 172 

Shipping and Handling Costs* $ 1,338 1,394 1,369 

*Amounts included in production and operating expenses. 

Foreign Currency Transaction (Gains) Losses—after-tax 

Alaska $ - - -

Lower 48 and Latin America - - 1 

Canada 5 (3) 10 

Europe 21 7 20 

Asia Pacific and Middle East 29 (23) (96) 

Other International 1 3 4 

LUKOIL Investment - (1) 15 

Corporate and Other 2 (16) 7 

 $ 58 (33) (39) 

 Millions of Dollars

 2012 2011 

Properties, Plants and Equipment 

Proved properties $ 111,458* 111,044 

Unproved properties 8,257* 7,846 

Discontinued operations—Downstream business - 23,566 

Other 6,464 6,753 

Gross properties, plants and equipment 126,179 149,209 

Accumulated depreciation (58,916) (65,029) 

Net properties, plants and equipment $ 67,263 84,180 

*Excludesassets held for sale reclassified to prepaid expenses and other current assets, including proved properties of $11,075 million and unproved properties of $234 million.

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Note 24—Related Party Transactions

We consider our equity method investments to be related parties. Significant transactions with related parties were:

 Millions of Dollars

 2012 2011 2010 

Operating revenues and other income $ 59 49 18 

Gains on dispositions* - - 1,149 

Purchases 261 327 656 

Operating expenses and selling, general and administrative expenses 183 233 238 

Net interest expense** 38 61 75 

* During 2010, we sold a portion of our LUKOIL shares under a stock purchase and option agreement with a wholly owned subsidiary of LUKOIL, resulting in a before-tax gain of

$1,149 million. Beginning in the fourth quarter of 2010, transactions with LUKOIL and its subsidiaries were no longer considered related party transactions. See Note 5—Assets

Held for Sale or Sold, for additional information.

** We paid interest to, or received interest from, various affiliates, including FCCL Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional

information on loans to affiliated companies.

Note 25—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. We manage our operations

through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle

East, and Other International.

On April 30, 2012, our Downstream business was separated into a stand-alone, publicly traded corporation, Phillips 66. In 2012, we also agreed to sell our

Nigerian and Algerian businesses and our interest in Kashagan. As such, results for these operations have been reported as discontinued operations in all

periods presented. Commodity sales to Phillips 66, which were previously eliminated in consolidation prior to the separation, are now reported as third-party

sales. For additional information, see Note 2—Discontinued Operations.

Our LUKOIL Investment represents our prior investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company

headquartered in Russia. We completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, ongoing costs

associated with the separation and certain technology activities, net of licensing revenues. Corporate assets include all cash and cash equivalents, short-term

investments and restricted cash.

We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Segment accounting policies are the same as those in Note

1—Accounting Policies. Intersegment sales are at prices that approximate market.

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Analysis of Results by Operating Segment

 Millions of Dollars

 2012 2011 2010 

Sales and Other Operating Revenues 

Alaska $ 9,502 9,533 7,462 

Lower 48 and Latin America 19,600 23,507 21,980 

Intersegment eliminations (230) (283) (180) 

Lower 48 and Latin America 19,370 23,224 21,800 

Canada 5,028 6,270 6,147 

Intersegment eliminations (475) (944) (797) 

Canada 4,553 5,326 5,350 

Europe 14,709 17,119 12,819 

Intersegment eliminations (72) (50) (17) 

Europe 14,637 17,069 12,802 

Asia Pacific and Middle East 7,705 8,665 7,161 

Intersegment eliminations (41) (1) (1) 

Asia Pacific and Middle East 7,664 8,664 7,160 

Other International 2,088 221 1,543 

LUKOIL Investment - - -

Corporate and Other 153 159 98 

Consolidated sales and other operating revenues $ 57,967 64,196 56,215

Depreciation, Depletion, Amortization and Impairments 

Alaska $ 520 578 626 

Lower 48 and Latin America 2,796 2,228 2,286 

Canada 1,600 1,758 1,680 

Europe 1,203 1,405 2,049 

Asia Pacific and Middle East 1,002 1,063 1,329 

Other International 45 8 44 

LUKOIL Investment - - -

Corporate and Other 94 108 71 

Consolidated depreciation, depletion, amortization and impairments $ 7,260 7,148 8,085 

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 Millions of Dollars

 

 2012 2011 2010 

Equity in Earnings of Affiliates 

Alaska $ 10 (77) 8 

Lower 48 and Latin America 86 9 9 80 

Canada 726 677 505 

Europe 29 46 41 

Asia Pacific and Middle East 1,057 819 (17) 

Other International 6 (324) (532) 

LUKOIL Investment - - 1,295 

Corporate and Other (3) (1) (4) 

Consolidated equity in earnings of affiliates $ 1,911 1,239 1,376

Income Taxes 

Alaska $ 1,266 1,171 1,017 

Lower 48 and Latin America 133 741 595 

Canada (252) (45) 215 

Europe 4,012 4,459 3,118 

Asia Pacific and Middle East 1,578 1,887 1,340 

Other International 1,485 162 1,170 

LUKOIL Investment - 123 505 

Corporate and Other (280) (290) (390) 

Consolidated income taxes $ 7,942 8,208 7,570 

Net Income Attributable to ConocoPhillips 

Alaska $ 2,276 1,984 1,727 

Lower 48 and Latin America 1,029 1,288 1,029 

Canada (684) 91 2,902 

Europe 1,498 1,830 1,703 

Asia Pacific and Middle East 3,928 3,032 2,099 

Other International 359 (377) (418) 

LUKOIL Investment - 239 2,513 

Corporate and Other (993) (960) (1,304) 

Discontinued operations 1,015 5,309 1,107 

Consolidated net income attributable to ConocoPhillips $ 8,428 12,436 11,358 

Investments In and Advances To Affiliates 

Alaska $ 56 58 143 

Lower 48 and Latin America 1,133 1,168 1,190 

Canada 9,973 9,045 8,675 

Europe 242 195 211 

Asia Pacific and Middle East 12,468 11,571 11,335 

Other International 61 339 813 

LUKOIL Investment - - - 

Corporate and Other 15 9 - 

Discontinued operations - 10,275 9,868 

Consolidated investments in and advances to affiliates $ 23,948 32,660 32,235 

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 Millions of Dollars

 2012 2011 2010 

Total Assets 

Alaska $ 10,950 10,723 10,832 

Lower 48 and Latin America 28,895 25,872 24,213 

Canada 22,308 20,847 21,168 

Europe 15,562 12,452 11,335 

Asia Pacific and Middle East 23,721 22,374 21,853 

Other International 1,418 1,542 2,050 

LUKOIL Investment - - 1,129 

Corporate and Other 6,823 8,485 11,974 

Discontinued operations 7,467 50,935 51,760 

Consolidated total assets $ 117,144 153,230 156,314 

Capital Expenditures and Investments 

Alaska $ 828 774 729 

Lower 48 and Latin America 5,251 3,882 1,790 

Canada 2,184 1,761 1,356 

Europe 2,860 2,222 1,190 

Asia Pacific and Middle East 2,430 2,325 2,157 

Other International 415 8 127 

LUKOIL Investment - - - 

Corporate and Other 204 242 186 

Consolidated capital expenditures and investments $ 14,172 11,214 7,535 

Interest Income and Expense 

Interest income 

Corporate $ 96 94 54 

Lower 48 and Latin America 47 51 54 

Asia Pacific and Middle East 11 7 8 

Other International 9 18 19 

Interest and debt expense 

Corporate $ 606 832 1,027 

Canada 103 122 140 

Sales and Other Operating Revenues by Product 

Crude oil $ 26,302 24,237 20,840 

Natural gas 25,163 29,915 28,550 

Natural gas liquids 2,416 3,101 2,817 

Other* 4,086 6,943 4,008 

Consolidated sales and other operating revenues by product $ 57,967  64,196  56,215 

* Includes LNG and bitumen.

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Geographic Information

 Millions of Dollars

 Sales and Other Operating Revenues* Long-Lived Assets**

 

 2012  2011  2010  2012  2011  2010 

United States $ 28,901 32,790 29,305 35,443 33,750 32,246 

Australia*** 3,371 3,458 2,789 13,483 12,572 12,461 

Canada 4,553 5,326 5,350 21,304 20,083 20,439 

China 1,499 2,154 1,870 2,408 2,449 2,656 

Indonesia 2,198 2,076 1,696 1,662 1,726 1,745 

Norway 5,059 5,755 4,692 7,288 5,918 5,664 

United Kingdom 9,578 11,314 8,110 4,480 3,257 2,975 

Other foreign countries 2,808 1,323 2,403 5,143 5,107 5,231 

Discontinued operations - - - - 31,978 31,372 

Worldwide consolidated $ 57,967 64,196 56,215 91,211 116,840 114,789 

 *Salesand other operating revenues are attributable to countries based on the location of the operations generating the revenues.

 **Definedas net PP&E plus investments in and advances to affiliated companies.

***Includesamounts related to the joint petroleum development area with shared ownership held by Australia and Timor-Leste.

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Oil and Gas Operations (Unaudited)

In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas,” and

regulations of the U.S. Securities and Exchange Commission (SEC), we are making certain supplemental disclosures about our oil and gas exploration and

production operations.

These disclosures include information about our consolidated oil and gas activities and our proportionate share of our equity affiliates’ oil and gas activities,

covering both those in our operating segments, as well as in our LUKOIL Investment segment. As a result, for periods prior to 2011, amounts reported as

equity affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported elsewhere in this report.

Our proved reserves include estimated quantities related to production sharing contracts (PSCs), which are reported under the “economic interest” method and

are subject to fluctuations in commodity prices; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to

recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline.

At December 31, 2012, approximately 9 percent of our total proved reserves were under PSCs, primarily in our Asia Pacific/Middle East geographic reporting

area.

Our disclosures by geographic area include the United States, Canada, Europe (primarily Norway and the United Kingdom), Russia, Asia Pacific/Middle

East, Africa and Other Areas. Other Areas primarily consists of the Caspian Region.

In the following disclosures, the synthetic oil classification included our past Syncrude mining operations, and the bitumen classification includes our

Surmont operations and the FCCL Partnership. In June 2010, we sold our interest in the Syncrude Canada Ltd. joint venture; accordingly, as of December 31,

2010, we no longer held synthetic oil reserves.

On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL over a period of time through the end of 2011. As a result of this sell down

of our interest, at the end of the third quarter of 2010 we ceased using equity-method accounting for our investment in LUKOIL. Accordingly, the

supplemental oil and gas disclosures reflect activity for LUKOIL through June 30, 2010, which, on a lag basis, results in three quarters of activity being

included in the year 2010 (the fourth quarter of 2009 and the first two quarters of 2010). Since the proved reserves tables are not on a lag basis, they reflect

activity for the first three quarters of 2010, at which point LUKOIL’s reserves were removed from our reserve quantities.

During the fourth quarter of 2012, we agreed to sell our interest in Kashagan, and the Algeria and Nigeria businesses, with closing on all three transactions

expected by mid-2013. These businesses were considered held for sale at December 31, 2012, and have been reported as discontinued operations. Accordingly,

the Results of Operations, Average Sales Prices and Net Production tables included within the supplemental oil and gas disclosures reflect the associated

earnings and production as discontinued operations.

In January 2013, we entered into an agreement to sell the majority of our properties in the Cedar Creek Anticline, with closing expected in the first quarter of

2013. At December 31, 2012, the asset was considered held for sale.

The proved reserves associated with all these assets held for sale at December 31, 2012, totaled 364 million barrels of oil equivalent (BOE) and are reflected in

the following reserves tables.

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Reserves Governance

The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and FASB. Proved reserves are those quantities

of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given

date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which

contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic

methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will

commence the project within a reasonable time. Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved

reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required

equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the

reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new

wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and reporting of proved reserves. This policy is

applied by the geologists and reservoir engineers in our Exploration and Production (E&P) business units around the world. As part of our internal control

process, each business unit’s reserve processes and controls are reviewed annually by an internal team which is headed by the Company’s Manager of

Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geologists, finance personnel and a senior representative from

DeGolyer and MacNaughton (D&M), reviews the business units’ reserves for adherence to SEC guidelines and company policy through on-site visits and

review of documentation. In addition to providing independent reviews, this internal team also ensures reserves are calculated using consistent and appropriate

standards and procedures. This team is independent of business unit line management and is responsible for reporting its findings to senior management and

our internal audit group. The team is responsible for communicating our reserves policy and procedures and is available for internal peer reviews and

consultation on major projects or technical issues throughout the year. All of our proved reserves held by consolidated companies and our share of equity

affiliates have been estimated by ConocoPhillips.

During 2012, our processes and controls used to assess over 90 percent of proved reserves as of December 31, 2012, were reviewed by D&M, a third-party

petroleum engineering consulting firm. The purpose of their review was to assess whether the adequacy and effectiveness of our internal processes and controls

used to determine estimates of proved reserves are in accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented D&M with

an overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data presented included pertinent seismic

information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating

procedures and relevant economic criteria. Management’s intent in retaining D&M to review its processes and controls was to provide objective third-party

input on these processes and controls. D&M’s opinion was that the general processes and controls employed by ConocoPhillips in estimating its December 31,

2012, proved reserves for the properties reviewed are in accordance with the SEC reserves definitions. D&M’s report is included as Exhibit 99 of this Annual

Report on Form 10-K.

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The technical person primarily responsible for overseeing the processes and internal controls used in the preparation of the company’s reserve estimates is the

Manager of Reserves Compliance and Reporting. This individual is a petroleum engineer with a bachelor’s degree in civil engineering. He is a member of the

Society of Petroleum Engineers (SPE) with over 30 years of oil and gas industry experience, including drilling and production engineering assignments in

several field locations. He has held positions of increasing responsibility in reservoir engineering, reserves reporting and compliance, and business

management.

Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting Estimates” section of Management’s

Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.

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Proved Reserves

Years Ended Crude Oil

December 31 Millions of Barrels

 

 Alaska

Lower

48

Total

U.S. Canada Europe Russia

Asia Pacific/

Middle East Africa

Other

Areas Total

Developed and Undeveloped 

Consolidated operations 

End of 2009 1,104 253 1,357 29 469 - 289 267 108 2,519 

Revisions 60 14 74 3 26 - 10 2 - 115 

Improved recovery 51 2 53 - - - 1 - - 54 

Purchases - - - - - - - - - - 

Extensions and discoveries 17 27 44 1 14 - 7 10 - 76 

Production (79) (30) (109) (5) (72) - (44) (27) - (257) 

Sales - (5) (5) (6) - - - - - (11) 

End of 2010 1,153 261 1,414 22 437 - 263 252 108 2,496 

Revisions 6 9 18 87 4 (5) - (6) 4 - 84 

Improved recovery 14 3 17 1 49 - 13 - - 80 

Purchases - - - - - - - - - - 

Extensions and discoveries 21 5 6 77 2 9 9 - 8 - - 186 

Production (73) (34) (107) (4) (60) - (36) (13) - (220) 

Sales - (8) (8) (1) - - - - - (9) 

End of 2011 1,184 296 1,480 24 520 - 242 243 108 2,617 

Revisions (2) 11 9 2 28 - 13 2 - 54 

Improved recovery 12 4 16 - - - - - - 16 

Purchases - - - - - - - - - - 

Extensions and discoveries 22 183 205 3 3 - 32 7 - 250 

Production (68) (47) (115) (5) (49) - (25) (23) - (217) 

Sales - - - - (15) - (21) - - (36) 

End of 2012 1,148 447 1,595 24 487 - 241 229 108 2,684 

Equity affiliates 

End of 2009 - - - - - 1,586 68 - - 1,654 

Revisions - - - - - 6 35 - - 41 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - - - - - - - - 

Production - - - - - (114) (1) - - (115) 

Sales - - - - - (1,403) - - - (1,403) 

End of 2010 - - - - - 75 102 - - 177 

Revisions - - - - - (37) - - - (37) 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - - - - - - - - 

Production - - - - - (11) (5) - - (16) 

Sales - - - - - - - - - - 

End of 2011 - - - - - 27 97 - - 124 

Revisions - - - - - 1 - - - 1 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - - - - - - - - 

Production - - - - - (5) (6) - - (11) 

Sales - - - - - (19) - - - (19) 

End of 2012 - - - - - 4 91 - - 95 

Total company 

End of 2009 1,104 253 1,357 29 469 1,586 357 267 108 4,173 

End of 2010 1,153 261 1,414 22 437 75 365 252 108 2,673 

End of 2011 1,184 296 1,480 24 520 27 339 243 108 2,741 

End of 2012 1,148 447 1,595 24 487 4 332 229 108 2,779 

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Years Ended Crude Oil

December 31 Millions of Barrels

 

 Alaska 

Lower

48 

Total

U.S. Canada Europe Russia 

Asia Pacific/

Middle East Africa 

Other

Areas Total

Developed 

Consolidated operations 

End of 2009 1,015 226 1,241 28 287 - 180 246 - 1,982

End of 2010 1,024 223 1,247 21 270 - 181 235 - 1,954

End of 2011 1,056 234 1,290 22 296 - 156 232 - 1,996

End of 2012 1,017 271 1,288 23 267 - 136 217 - 1,931

Equity affiliates 

End of 2009 - - - - - 1,199 - - - 1,199

End of 2010 - - - - - 73 102 - - 175

End of 2011 - - - - - 27 97 - - 124

End of 2012 - - - - - 4 91 - - 9 5

Undeveloped 

Consolidated operations 

End of 2009 89 27 116 1 182 - 109 21 108 537

End of 2010 129 38 167 1 167 - 82 17 108 542

End of 2011 128 62 190 2 224 - 86 11 108 621

End of 2012 131 176 307 1 220 - 105 12 108 753

Equity affiliates 

End of 2009 - - - - - 387 68 - - 455

End of 2010 - - - - - 2 - - - 2

End of 2011 - - - - - - - - - -

End of 2012 - - - - - - - - - -

Notable changes in proved crude oil reserves in the three years ended December 31, 2012, included:

• Extensions and discoveries: In 2012, extensions and discoveries in Lower 48 were primarily due to continued drilling success in Eagle Ford and

Bakken. In 2011, extensions and discoveries in Europe were primarily due to the sanctioning of the Ekofisk South and Clair Ridge developments

in the North Sea.

• Sales: In 2010, for our equity affiliates in Russia, sales were primarily due to the disposition of our interest in LUKOIL.

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Years Ended Natural Gas Liquids

December 31 Millions of Barrels

 

 Alaska

Lower

48

Total

U.S. Canada Europe Russia

Asia Pacific/

Middle East Africa

Other

Areas Total

Developed and Undeveloped 

Consolidated operations 

End of 2009 116 432 548 52 32 - 43 - - 675 

Revisions 21 (6) 15 12 2 - (3) 19 - 45 

Improved recovery - - - - - - 4 - - 4 

Purchases - 1 1 - - - - - - 1 

Extensions and discoveries - 3 3 3 4 - - - - 10 

Production (5) (25) (30) (9) (6) - (7) (1) - (53) 

Sales - (17) (17) - - - - - - (17) 

End of 2010 132 388 520 58 32 - 37 18 - 665 

Revisions 1 27 28 6 2 - (1) 1 - 36 

Improved recovery - - - - 2 - - - - 2 

Purchases - 1 1 - - - - - - 1 

Extensions and discoveries - 12 12 2 3 - - - - 17 

Production (6) (26) (32) (9) (4) - (5) (1) - (51) 

Sales - - - - - - - - - - 

End of 2011 127 402 529 57 35 - 31 18 - 670 

Revisions 1 (10) (9) 1 (2) - (3) - - (13) 

Improved recovery - - - - - - - - - - 

Purchases - 1 1 - - - - - - 1 

Extensions and discoveries - 40 40 3 - - - - - 43 

Production (6) (30) (36) (9) (2) - (6) (1) - (54) 

Sales - - - - (1) - - - - (1) 

End of 2012 122 403 525 52 30 - 22 17 - 646 

Equity affiliates 

End of 2009 - - - - - 18 38 - - 56 

Revisions - - - - - - 16 - - 16 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - - - - - - - - 

Production - - - - - - - - - - 

Sales - - - - - (18) - - - (18) 

End of 2010 - - - - - - 54 - - 54 

Revisions - - - - - - - - - - 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - - - - - - - - 

Production - - - - - - (3) - - (3) 

Sales - - - - - - - - - - 

End of 2011 - - - - - - 51 - - 51 

Revisions - - - - - - - - - - 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - - - - - - - - 

Production - - - - - - (3) - - (3) 

Sales - - - - - - - - - - 

End of 2012 - - - - - - 48 - - 48 

Total company 

End of 2009 116 432 548 52 32 18 81 - - 731 

End of 2010 132 388 520 58 32 - 91 18 - 719 

End of 2011 127 402 529 57 35 - 82 18 - 721 

End of 2012 122 403 525 52 30 - 70 17 - 694 

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Years Ended Natural Gas Liquids

December 31 Millions of Barrels

 Alaska 

Lower

48 

Total

U.S. Canada Europe Russia 

Asia Pacific/

Middle East Africa 

Other

Areas Total

Developed 

Consolidated operations 

End of 2009 115 332 447 49 25 - 41 - - 562

End of 2010 131 311 442 54 20 - 37 16 - 569

End of 2011 126 330 456 52 21 - 31 16 - 576

End of 2012 121 335 456 49 17 - 22 15 - 559

Equity affiliates 

End of 2009 - - - - - 14 - - - 14

End of 2010 - - - - - - 54 - - 54

End of 2011 - - - - - - 51 - - 51

End of 2012 - - - - - - 48 - - 48

Undeveloped 

Consolidated operations 

End of 2009 1 100 101 3 7 - 2 - - 113

End of 2010 1 77 78 4 12 - - 2 - 9 6

End of 2011 1 72 73 5 14 - - 2 - 94

End of 2012 1 68 6 9 3 13 - - 2 - 87

Equity affiliates 

End of 2009 - - - - - 4 38 - - 42

End of 2010 - - - - - - - - - -

End of 2011 - - - - - - - - - -

End of 2012 - - - - - - - - - -

Notable changes in proved natural gas liquids reserves in the three years ended December 31, 2012, included:

• Extensions and discoveries: In 2012, extensions and discoveries in Lower 48 were primarily due to continued drilling success in Eagle Ford,

Barnett and Bakken.

• Sales: In 2010, for our equity affiliates in Russia, sales were primarily due to the disposition of our interest in LUKOIL.

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Years Ended Natural Gas

December 31 Billions of Cubic Feet

 Alaska

Lower

48

Total

U.S. Canada Europe Russia

Asia Pacific/

Middle East Africa

Other

Areas Total

Developed and Undeveloped 

Consolidated operations 

End of 2009 2,780 7,962 10,742 2,296 2,009 - 2,912 950 5 6 18,965 

Revisions 155 365 520 309 86 - (39) 36 - 912 

Improved recovery 24 1 25 - - - - - - 25 

Purchases - 9 9 - - - - - - 9 

Extensions and discoveries 4 122 126 84 89 - 24 - - 323 

Production (101) (663) (764) (358) (323) - (289) (60) - (1,794) 

Sales - (179) (179) (26) - - - - - (205) 

End of 2010 2,862 7,617 10,479 2,305 1,861 - 2,608 926 5 6 18,235 

Revisions 186 15 201 134 70 - (8) 9 - 406 

Improved recovery 1 5 6 - 53 - - - - 59 

Purchases - 7 7 1 - - - - - 8 

Extensions and discoveries 3 171 174 78 158 - 192 - - 602 

Production (92) (616) (708) (338) (246) - (277) (63) - (1,632) 

Sales - (11) (11) (67) - - - - - (78) 

End of 2011 2,960 7,188 10,148 2,113 1,896 - 2,515 872 5 6 17,600 

Revisions (24) (459) (483) (111) 9 6 - 113 109 2 (274) 

Improved recovery 20 7 27 - - - - - - 27 

Purchases - 9 9 2 - - - - - 11 

Extensions and discoveries 4 447 451 75 36 - 14 2 - 578 

Production (90) (595) (685) (313) (208) - (263) (70) - (1,539) 

Sales - - - (2) (14) - (31) - - (47) 

End of 2012 2,870 6,597 9,467 1,764 1,806 - 2,348 913 58 16,356 

Equity affiliates 

End of 2009 - - - - - 2,705 2,577 - - 5,282 

Revisions - - - - - 19 683 - - 702 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - - - - 269 - - 269 

Production - - - - - (91) (65) - - (156) 

Sales - - - - - (2,616) - - - (2,616) 

End of 2010 - - - - - 17 3,464 - - 3,481 

Revisions - - - - - (11) (76) - - (87) 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - - - - 259 - - 259 

Production - - - - - (2) (184) - - (186) 

Sales - - - - - - (151) - - (151) 

End of 2011 - - - - - 4 3,312 - - 3,316 

Revisions - - - - - - (75) - - (75) 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - - - - 330 - - 330 

Production - - - - - (1) (182) - - (183) 

Sales - - - - - (3) (127) - - (130) 

End of 2012 - - - - - - 3,258 - - 3,258 

Total company 

End of 2009 2,780 7,962 10,742 2,296 2,009 2,705 5,489 950 5 6 24,247 

End of 2010 2,862 7,617 10,479 2,305 1,861 17 6,072 926 5 6 21,716 

End of 2011 2,960 7,188 10,148 2,113 1,896 4 5,827 872 5 6 20,916 

End of 2012 2,870 6,597 9,467 1,764 1,806 - 5,606 913 58 19,614 

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Years Ended Natural Gas

December 31 Billions of Cubic Feet

 Alaska 

Lower

48 

Total

U.S. Canada Europe Russia 

Asia Pacific/

Middle East Africa 

Other

Areas Total

Developed 

Consolidated operations 

End of 2009 2,744 6,633 9,377 2,173 1,772 - 2,537 889 - 16,748 

End of 2010 2,785 6,399 9,184 2,134 1,529 - 2,136 865 - 15,848 

End of 2011 2,907 6,194 9,101 1,932 1,439 - 1,932 738 - 15,142 

End of 2012 2,805 5,737 8,542 1,684 1,290 - 1,696 846 - 14,058 

Equity affiliates 

End of 2009 - - - - - 1,506 307 - - 1,813 

End of 2010 - - - - - 17 3,114 - - 3,131 

End of 2011 - - - - - 4 2,943 - - 2,947 

End of 2012 - - - - - - 2,723 - - 2,723 

Undeveloped 

Consolidated operations 

End of 2009 36 1,329 1,365 123 237 - 375 61 5 6 2,217 

End of 2010 77 1,218 1,295 171 332 - 472 61 5 6 2,387 

End of 2011 53 994 1,047 181 457 - 583 134 5 6 2,458 

End of 2012 6 5 860 925 80 516 - 652 67 58 2,298 

Equity affiliates 

End of 2009 - - - - - 1,199 2,270 - - 3,469 

End of 2010 - - - - - - 350 - - 350 

End of 2011 - - - - - - 369 - - 369 

End of 2012 - - - - - - 535 - - 535 

Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily because the quantities

above include gas consumed at the lease.

Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

Notable changes in proved natural gas reserves in the three years ended December 31, 2012, included:

• Revisions: In 2012, revisions in Lower 48 were primarily due to lower prices in 2012, versus 2011. In 2012, revisions in Canada were primarily

due to lower prices in 2012, versus 2011, as well as improved well performance. In our consolidated operations in Asia Pacific/Middle East,

revisions in 2012 were primarily due to development activities in various fields. Revisions in Africa in 2012 were primarily due the execution of a

gas sales agreement. In 2010, revisions in Alaska, Lower 48 and Canada were primarily due to higher prices in 2010, versus 2009, as well as

improved well performance.

• Extensions and discoveries: In 2012, 2011 and 2010, extensions and discoveries in Lower 48 were primarily due to continued drilling success in

various fields. In 2012 and 2011, for our equity affiliate operations in Asia Pacific/Middle East, extensions and discoveries were primarily due to

APLNG’s ongoing development drilling onshore Australia. In 2010, extensions and discoveries in Canada were primarily due to continued drilling

success in various fields.

• Sales: In 2012, for our equity affiliates in Asia Pacific/Middle East, sales were primarily due to the dilution of our interest in APLNG. In 2010,

for our equity affiliates in Russia, sales were primarily due to the disposition of our interest in LUKOIL.

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Years Ended Other Products

December 31 Millions of Barrels

 Synthetic Oil Bitumen 

 Canada Canada

Developed and Undeveloped 

Consolidated operations 

End of 2009 248 417 

Revisions - 42 

Improved recovery - - 

Purchases - - 

Extensions and discoveries - - 

Production (4) (4) 

Sales (244) - 

End of 2010 - 455 

Revisions - (1) 

Improved recovery - - 

Purchases - - 

Extensions and discoveries - 79 

Production - (3) 

Sales - - 

End of 2011 - 530 

Revisions - (20) 

Improved recovery - - 

Purchases - - 

Extensions and discoveries - - 

Production - (4) 

Sales - - 

End of 2012 - 506 

Equity affiliates 

End of 2009 - 716 

Revisions - 13 

Improved recovery - - 

Purchases - - 

Extensions and discoveries - 133 

Production - (18) 

Sales - - 

End of 2010 - 844 

Revisions - (101) 

Improved recovery - - 

Purchases - - 

Extensions and discoveries - 187 

Production - (21) 

Sales - - 

End of 2011 - 909 

Revisions - 207 

Improved recovery - - 

Purchases - - 

Extensions and discoveries - 307 

Production - (29) 

Sales - - 

End of 2012 - 1,394 

Total company 

End of 2009 248 1,133 

End of 2010 - 1,299 

End of 2011 - 1,439 

End of 2012 - 1,900 

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Years Ended Other Products

December 31 Millions of Barrels

 Synthetic Oil Bitumen 

 Canada Canada

Developed 

Consolidated operations 

End of 2009 248 24

End of 2010 - 34

End of 2011 - 29

End of 2012 - 25

Equity affiliates 

End of 2009 - 116

End of 2010 - 142

End of 2011 - 131

End of 2012 - 170

Undeveloped 

Consolidated operations 

End of 2009 - 393

End of 2010 - 421

End of 2011 - 501

End of 2012 - 481

Equity affiliates 

End of 2009 - 600

End of 2010 - 702

End of 2011 - 778

End of 2012 - 1,224

Notable changes in proved synthetic oil and bitumen reserves in the three years ended December 31, 2012, included:

• Revisions: In 2012, for our bitumen equity operations, revisions were primarily due to well performance and denser well spacing at Foster Creek

and Christina Lake. In 2011, for our bitumen equity operations, revisions were primarily due to new subsurface interpretations, as well as the

effects of higher prices on sliding scale royalty provisions.

• Extensions and discoveries: In 2012, for our bitumen equity operations, extensions and discoveries were primarily related to the sanctioning of

Christina Lake Phase F and Narrows Lake Phase A. In 2011, for our consolidated operations, extensions and discoveries were related to continued

development of Surmont. In 2011 and 2010, for our equity affiliate operations, extensions and discoveries mainly reflect the continued

development of FCCL.

• Sales: In 2010, for synthetic oil consolidated operations, sales reflect the disposition of our interest in Syncrude.

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Years Ended Total Proved Reserves

December 31 Millions of Barrels of Oil Equivalent

 Alaska

Lower

48

Total

U.S. Canada Europe Russia 

Asia Pacific/

Middle East Africa

Other

Areas Total

Developed and Undeveloped 

Consolidated operations 

End of 2009 1,684 2,012 3,696 1,129 836 - 817 425 117 7,020 

Revisions 107 68 175 109 42 - 1 27 - 354 

Improved recovery 5 5 2 57 - - - 5 - - 62 

Purchases - 2 2 - - - - - - 2 

Extensions and discoveries 17 51 68 18 33 - 11 10 - 140 

Production (101) (165) (266) (82) (132) - (99) (38) - (617) 

Sales - (52) (52) (254) - - - - - (306) 

End of 2010 1,762 1,918 3,680 920 779 - 735 424 117 6,655 

Revisions 101 48 149 31 8 - (9) 7 - 186 

Improved recovery 14 4 18 1 60 - 13 - - 92 

Purchases - 2 2 - - - - - - 2 

Extensions and discoveries 21 97 118 97 128 - 40 - - 383 

Production (94) (163) (257) (73) (105) - (86) (25) - (546) 

Sales - (10) (10) (12) - - - - - (22) 

End of 2011 1,804 1,896 3,700 964 870 - 693 406 117 6,750 

Revisions (5) (75) (80) (36) 42 - 29 20 - (25) 

Improved recovery 16 5 21 - - - - - - 21 

Purchases - 3 3 - - - - - - 3 

Extensions and discoveries 22 297 319 19 10 - 34 7 - 389 

Production (89) (176) (265) (71) (86) - (74) (35) - (531) 

Sales - - - - (18) - (27) - - (45) 

End of 2012 1,748 1,950 3,698 876 818 - 655 398 117 6,562 

Equity affiliates 

End of 2009 - - - 716 - 2,055 535 - - 3,306 

Revisions - - - 13 - 9 165 - - 187 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - 133 - - 45 - - 178 

Production - - - (18) - (129) (12) - - (159) 

Sales - - - - - (1,857)* - - - (1,857) 

End of 2010 - - - 844 - 78 733 - - 1,655 

Revisions - - - (101) - (39) (12) - - (152) 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - 187 - - 43 - - 230 

Production - - - (21) - (11) (39) - - (71) 

Sales - - - - - - (25) - - (25) 

End of 2011 - - - 909 - 28 700 - - 1,637 

Revisions - - - 207 - 1 (13) - - 195 

Improved recovery - - - - - - - - - - 

Purchases - - - - - - - - - - 

Extensions and discoveries - - - 307 - - 5 5 - - 362 

Production - - - (29) - (5) (39) - - (73) 

Sales - - - - - (20) (21) - - (41) 

End of 2012 - - - 1,394 - 4 682 - - 2,080 

Total company 

End of 2009 1,684 2,012 3,696 1,845 836 2,055 1,352 425 117 10,326 

End of 2010 1,762 1,918 3,680 1,764 779 78 1,468 424 117 8,310 

End of 2011 1,804 1,896 3,700 1,873 870 28 1,393 406 117 8,387 

End of 2012 1,748 1,950 3,698 2,270 818 4 1,337 398 117 8,642 

*Includes594 million BOE due to the cessation of equity accounting.

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Years Ended Total Proved Reserves

December 31 Millions of Barrels of Oil Equivalent

 Alaska 

Lower

48

 

 

Total

U.S.

 

 Canada Europe Russia 

Asia Pacific/

Middle East

 

 Africa 

Other

Areas

 

 Total 

Developed 

Consolidated operations 

End of 2009 1,588 1,663 3,251 711 608 - 644 394 - 5,608 

End of 2010 1,619 1,601 3,220 465 545 - 574 396 - 5,200 

End of 2011 1,666 1,597 3,263 425 556 - 510 371 - 5,125 

End of 2012 1,606 1,562 3,168 377 499 - 441 373 - 4,858 

Equity affiliates 

End of 2009 - - - 116 - 1,464 51 - - 1,631 

End of 2010 - - - 142 - 76 675 - - 893 

End of 2011 - - - 131 - 28 638 - - 797 

End of 2012 - - - 170 - 4 593 - - 767 

Undeveloped 

Consolidated operations 

End of 2009 9 6 349 445 418 228 - 173 31 117 1,412 

End of 2010 143 317 460 455 234 - 161 28 117 1,455 

End of 2011 138 299 437 539 314 - 183 35 117 1,625 

End of 2012 142 388 530 499 319 - 214 25 117 1,704 

Equity affiliates 

End of 2009 - - - 600 - 591 484 - - 1,675 

End of 2010 - - - 702 - 2 58 - - 762 

End of 2011 - - - 778 - - 62 - - 840 

End of 2012 - - - 1,224 - - 89 - - 1,313 

Natural gas reserves are converted to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE.

Proved Undeveloped Reserves

We had 3,017 million BOE of proved undeveloped reserves at year-end 2012, compared with 2,465 million BOE at year-end 2011. We converted 247 million

BOE of undeveloped reserves to developed during 2012 as we achieved startup of major development projects. In addition, we added 799 million BOE of

undeveloped reserves in 2012 mainly through extensions and discoveries from ongoing development progress and exploration success, as well as through

revisions. As a result, at December 31, 2012, our proved undeveloped reserves represented 35 percent of total proved reserves, compared with 29 percent at

December 31, 2011. Costs incurred for the year ended December 31, 2012, relating to the development of proved undeveloped reserves were $7.7 billion.

Approximately 70 percent of our proved undeveloped reserves at year-end 2012 were associated with seven major development areas. Five of the major

development areas are currently producing and are expected to have proved undeveloped reserves convert to developed over time as development activities

continue and/or production facilities are expanded or upgraded, and include:

• FCCL oil sands—Foster Creek and Christina Lake in Canada.

• The Surmont oil sands project in Canada.

• The Ekofisk Field in the North Sea.

• The Eagle Ford area in the Lower 48.

The remaining major projects include the Kashagan Field in Kazakhstan and Narrows Lake in our FCCL oil sands in Canada. In November, we announced

our intention to sell our interest in Kashagan, and the transaction is expected to close by mid-2013. Narrows Lake was sanctioned for development in 2012.

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At the end of 2012, we did not have any material amounts of proved undeveloped reserves in individual fields or countries that have remained undeveloped for

five years or more. However, our largest concentrations of proved undeveloped reserves at year-end 2012 are located in the Athabasca oil sands in Canada,

consisting of the FCCL and Surmont steam-assisted gravity drainage (SAGD) projects. The majority of our remaining proved undeveloped reserves in this

area were recorded beginning in 2007, and we expect a material portion of these reserves will remain undeveloped for more than five years.

Our SAGD projects are large, multi-year projects with steady, long-term production at consistent levels. The associated reserves are expected to be developed

over many years as additional well pairs are drilled across the extensive resource base to maintain throughput at the central processing facilities.

Results of Operations

The Company’s results of operations from oil and gas activities for the years 2012, 2011 and 2010 are shown in the following tables. Additional information

about selected line items within the results of operations tables is shown below:

• Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other

miscellaneous income.

• Taxes other than income taxes include production, property and other non-income taxes.

• Depreciation of support equipment is reclassified as applicable.

• Transportation costs include costs to transport our produced hydrocarbons to their points of sale, as well as processing fees paid to process

natural gas to natural gas liquids. The profit element of transportation operations in which we have an ownership interest is deemed to be outside

oil and gas producing activities. The net income of the transportation operations is included in other earnings.

• Other related expenses include foreign currency transaction gains and losses and other miscellaneous expenses.

• Other earnings include non-oil and gas activities, such as pipeline and marine operations, liquefied natural gas operations, and crude oil and gas

marketing activities.

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Results of Operations

Year Ended Millions of Dollars

December 31, 2012 Lower Total Asia Pacific/ Other Disc

Alaska 48 U.S. Canada Europe Russia Middle East Africa Areas Ops Total

Consolidated operations 

Sales $ 8,306 6,386 14,692 1,722 7,630 - 4,802 1,739 - 1,124 31,709

Transfers 38 309 347 - - - 867 - - - 1,214

Other revenues (1) 70 6 9 107 568 - 930 258 27 1 1,960 

Total revenues 8,343 6,765 15,108 1,829 8,198 - 6,599 1,997 27 1,125 34,883 

Production costs excluding taxes 1,108 1,460 2,568 788 978 - 754 5 6 - 240 5,384

Taxes other than income taxes 2,477 513 2,990 6 5 24 1 321 2 5 21 3,429

Exploration expenses 34 343 377 633 102 1 70 5 5 210 20 1,468

Depreciation, depletion and

amortization 421 2,561 2,982 1,335 958 1 883 44 - 181 6,384 

Impairments - 192 192 162 211 - 4 - - 606 1,175

Transportation costs 680 368 1,048 113 233 - 113 3 - 22 1,532

Other related expenses 133 136 269 79 (14) 18 107 8 6 58 531

Accretion 5 5 6 6 121 57 186 - 21 - - 8 393 

3,435 1,126 4,561 (1,403) 5,520 (21) 4,326 1,829 (194) (31) 14,587

Provision for income taxes 1,229 209 1,438 (391) 3,980 6 1,514 1,728 (23) 183 8,435

Results of operations 2,206 917 3,123 (1,012) 1,540 (27) 2,812 101 (171) (214) 6,152

Other earnings 67 (175) (108) (209) 9 8 253 - 76 10 39

Net income (loss) attributable to

ConocoPhillips $ 2,273 742 3,015 (1,221) 1,549 (19) 3,065 101 (95) (204) 6,191 

Equity affiliates 

Sales $ - - - 1,566 - 443 930 - - - 2,939

Transfers - - - - - - 1,387 - - - 1,387

Other revenues - - - 16 - 206 (117) - 201 - 306 

Total revenues - - - 1,582 - 649 2,200 - 201 - 4,632 

Production costs excluding taxes - - - 470 - 45 135 - - - 650

Taxes other than income taxes - - - 9 - 293 1,153 - - - 1,455

Exploration expenses - - - 36 2 4 1 - - - 43

Depreciation, depletion and

amortization - - - 325 - 15 109 - - - 449

Impairments - - - - - - - - - - -

Transportation costs - - - - - 74 21 - - - 9 5

Other related expenses - - - 11 - 1 16 - - - 28

Accretion - - - 6 - 1 4 - - - 11

- - - 725 (2) 216 761 - 201 - 1,901 

Provision for income taxes - - - 181 - (233) (29) - - - (81) 

Results of operations - - - 544 (2) 449 790 - 201 - 1,982 

Other earnings - - - - - 1 100 - - - 101

Net income (loss) attributable to

ConocoPhillips $ - - - 544 (2) 450 890 - 201 - 2,083 

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Year Ended Millions of Dollars

December 31, 2011

 Alaska

Lower

48

Total

U.S. Canada Europe Russia

Asia Pacific/

Middle East* Africa

Other

Areas

Disc

Ops Total

Consolidated operations 

Sales** $ 8,143 6,396 14,539 2,299 9,087 - 6,024 185 - 1,355 33,489

Transfers** 45 400 445 - - - 809 - - - 1,254

Other revenues (46) 303 257 138 (16) - 15 21 16 9 440 

Total revenues 8,142 7,099 15,241 2,437 9,071 - 6,848 206 16 1,364 35,183 

Production costs excluding taxes 1,023 1,286 2,309 781 956 - 742 41 - 225 5,054

Taxes other than income taxes 2,721 520 3,241 6 5 4 1 543 2 - 21 3,877

Exploration expenses 36 368 404 177 201 - 192 36 40 29 1,079

Depreciation, depletion and

amortization 468 2,113 2,581 1,504 1,407 1 940 8 - 180 6,621

Impairments 2 71 73 253 (38) - - - - - 288

Transportation costs 609 432 1,041 128 273 - 120 4 - 23 1,589

Other related expenses 48 105 153 5 9 43 26 74 - 7 54 416

Accretion 5 9 58 117 50 203 - 23 - - 3 396

 3,176 2,146 5,322 (580) 6,022 (28) 4,214 115 (31) 829 15,863 

Provision for income taxes 1,167 755 1,922 (194) 4,355 3 1,844 160 (6) 545 8,629

Results of operations 2,009 1,391 3,400 (386) 1,667 (31) 2,370 (45) (25) 284 7,234 

Other earnings (46) (217) (263) (37) 189 16 201 14 101 (17) 204

Net income (loss) attributable to

ConocoPhillips $1,963 1,174 3,137 (423) 1,856 (15) 2,571 (31) 76 267 7,438 

Equity affiliates 

Sales $ - - - 1,295 - 1,107 956 - - - 3,358

Transfers - - - - - - 900 - - - 900

Other revenues - - - 6 - - (273) - - - (267) 

Total revenues - - - 1,301 - 1,107 1,583 - - - 3,991 

Production costs excluding taxes - - - 367 - 72 108 - - - 547

Taxes other than income taxes - - - 5 - 750 881 - - - 1,636

Exploration expenses - - - 36 - 1 2 - - - 39

Depreciation, depletion and

amortization - - - 209 - 52 112 - - - 373

Impairments - - - - - 395 - - - - 395

Transportation costs - - - - - 139 15 - - - 154

Other related expenses - - - 3 - - (4) - - - (1) 

Accretion - - - 4 - 1 3 - - - 8

 

- - - 677 - (303) 466 - - - 840 

Provision for income taxes - - - 159 - 18 32 - - - 209

Results of operations - - - 518 - (321) 434 - - - 631 

Other earnings - - - - - 238 9 9 - - - 337

Net income (loss) attributable to

ConocoPhillips $ - - - 518 - (83) 533 - - - 968 

* Certain amounts have been restated to reflect revised natural gas prices, reclassify amounts previously considered non-oil and gas producing activities and reclassify amounts

between consolidated and equity affiliates .

** Commodity sales to Phillips 66, reported as transfers prior to the separation, are now reported as third-party sales.

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Table of Contents

Year Ended

December 31, 2010

Millions of Dollars

Lower Total Asia Pacific/ Other Disc

Alaska 48 U.S. Canada Europe Russia Middle East Africa Areas Ops Total

Consolidated operations

Sales* $6,270 5,685 11,955 2,625 8,245 - 5,090 1,286 - 907 30,108

Transfers* 68 304 372 - - - 638 - - - 1,010

Other revenues - 559 559 3,216 142 - 5 5 167 18 5 4,162

Total revenues 6,338 6,548 12,886 5,841 8,387 - 5,783 1,453 18 912 35,280

Production costs excluding taxes 849 1,230 2,079 873 1,004 - 538 57 - 239 4,790

Taxes other than income taxes 1,570 498 2,068 74 6 1 355 3 1 15 2,523

Exploration expenses 37 292 329 295 146 2 260 19 81 30 1,162

Depreciation, depletion and

amortization 529 2,231 2,760 1,666 1,972 2 1,206 44 - 158 7,808

Impairments 4 19 23 13 43 - - - - - 79

Transportation costs 528 424 952 134 281 - 119 4 - 19 1,509

Other related expenses (38) 138 100 31 3 21 (60) 27 3 48 173

Accretion 58 5 5 113 50 192 - 24 - - 4 383

2,801 1,661 4,462 2,705 4,740 (26) 3,341 1,299 (67) 399 16,853

Provision for income taxes 1,014 555 1,569 108 3,066 (23) 1,361 1,177 (10) 263 7,511

Results of operations 1,787 1,106 2,893 2,597 1,674 (3) 1,980 122 (57) 136 9,342

Other earnings (75) (136) (211) (56) 51 31 215 (9) 89 8 118

Net income (loss) attributable to

ConocoPhillips $1,712 970 2,682 2,541 1,725 28 2,195 113 32 144 9,460

Equity affiliates

Sales $ - - - 955 - 5,189 249 - - - 6,393

Transfers - - - - - 1,876 - - - - 1,876

Other revenues - - - 7 - 1,219 10 - - - 1,236

Total revenues - - - 962 - 8,284 259 - - - 9,505

Production costs excluding taxes - - - 265 - 544 5 9 - - - 868

Taxes other than income taxes - - - 4 - 3,463 42 - - - 3,509

Exploration expenses - - - - - 61 (2) - - - 5 9

Depreciation, depletion and

amortization - - - 190 - 568 5 5 - - - 813

Impairments - - - - - 645 - - - - 645

Transportation costs - - - - - 784 25 - - - 809

Other related expenses - - - (3) - - 44 - - - 41

Accretion - - - 2 - 7 2 - - - 11

- - - 504 - 2,212 34 - - - 2,750

Provision for income taxes - - - 128 - 647 (25) - - - 750

Results of operations - - - 376 - 1,565 5 9 - - - 2,000

Other earnings - - - - - 405 (86) - - - 319

Net income (loss) attributable to

ConocoPhillips $ - - - 376 - 1,970 (27) - - - 2,319

* Commodity sales to Phillips 66, reported as transfers prior to the separation, are now reported as third-party sales.

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Table of Contents

Statistics

Net Production 2012 2011 2010

 Thousands of Barrels Daily

Crude Oil 

Consolidated operations 

Alaska 188 200 215

Lower 48 123 94 85

United States 311 294 300

Canada 13 12 15

Europe 135 164 196

Asia Pacific/Middle East 68 9 9 122

Africa 40 8 46

Total consolidated operations 567 577 679

Equity affiliates 

Russia 13 29 336

Asia Pacific/Middle East 15 16 2

Total equity affiliates 28 45 338

Total continuing operations 595 622 1,017

Discontinued operations 23 28 30

Total company 618 650 1,047

Natural Gas Liquids 

Consolidated operations 

Alaska 16 15 15

Lower 48 85 74 75

United States 101 89 90

Canada 24 26 23

Europe 7 11 15

Asia Pacific/Middle East 16 12 18

Total consolidated operations 148 138 146

Equity affiliates—Asia Pacific/Middle East 8 7 1

Total continuing operations 156 145 147

Discontinued operations 4 4 3

Total company 160 149 150

Synthetic Oil 

Consolidated operations—Canada - - 12

Bitumen 

Consolidated operations—Canada 12 10 10

Equity affiliates—Canada 81 57 49

Total company 93 67 5 9

Natural Gas Millions of Cubic Feet Daily 

Consolidated operations 

Alaska 55 61 82

Lower 48 1,493 1,556 1,695

United States 1,548 1,617 1,777

Canada 857 928 984

Europe 516 626 815

Asia Pacific/Middle East 672 695 712

Africa 18 1 8

Total consolidated operations 3,611 3,867 4,296

Equity affiliates 

Russia - - 254

Asia Pacific/Middle East 485 492 169

Total equity affiliates 485 492 423

Total continuing operations 4,096 4,359 4,719

Discontinued operations 149 157 141

Total company 4,245 4,516 4,860

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Average Sales Prices 2012 2011 2010

Crude Oil Per Barrel 

Consolidated operations 

Alaska $ 109.62  105.95  78.65

Lower 48 91.67 92.79 73.52

United States 102.90 101.89 77.19

Canada 78.26 86.04 67.99

Europe 113.08 111.82 79.74

Asia Pacific/Middle East 108.20 109.84 77.69

Africa 110.75 98.30 79.22

Total international 109.64 109.76 78.57

Total consolidated operations 105.86 105.68 77.96

Equity affiliates 

Russia 96.50 101.62 56.65

Asia Pacific/Middle East 108.07 106.96 89.24

Total equity affiliates 102.80 103.42 56.86 

Total continuing operations 105.72 105.52 70.94 

Discontinued operations 112.90 113.43 80.15

Natural Gas Liquids Per Barrel 

Consolidated operations 

Lower 48 $ 35.45 50.55 39.92

United States 35.45 50.55 39.92

Canada 48.64 56.84 47.68

Europe 61.53 59.19 46.75

Asia Pacific/Middle East 79.26 72.87 60.57

Total international 61.01 61.27 51.43

Total consolidated operations 44.62 54.79 45.91

Equity affiliates—Asia Pacific/Middle East 77.30 70.62 65.16

Total continuing operations 46.36 55.73 46.00

Discontinued operations 13.30 13.63 11.26

Synthetic Oil Per Barrel 

Consolidated operations—Canada $ - - 77.56

Bitumen Per Barrel 

Consolidated operations—Canada $ 57.58 55.16 51.10

Equity affiliates—Canada 53.39 63.93 53.43

Natural Gas Per Thousand Cubic Feet 

Consolidated operations 

Alaska $ 4.22 4.56 4.62

Lower 48 2.67 3.99 4.25

United States 2.72 4.01 4.27

Canada 2.13 3.46 3.74

Europe 9.76 9.26 6.94

Asia Pacific/Middle East 10.63 9.82 7.39

Africa 5.55 0.09 0.09

Total international 6.84 7.04 5.80

Total consolidated operations 5.07 5.78 5.17

Equity affiliates 

Russia - - 1.18

Asia Pacific/Middle East* 8.54 5.93 1.91

Total equity affiliates 8.54 5.93 1.47

Total continuing operations 5.48 5.80 4.84 

Discontinued operations 2.57 2.25 1.86

* Prior periods have been restated to reflect revised equity affiliates natural gas prices.

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 2012 2011 2010

Average Production Costs Per Barrel of Oil Equivalent* 

Consolidated operations 

Alaska $ 14.20  12.45  9.55

Lower 48 8.73 8.24 7.62

United States 10.47 9.70 8.30

Canada 11.22 10.56 10.68

Europe 11.72 9.38 7.93

Asia Pacific/Middle East 10.46 8.96 5.70

Africa 3.56 13.75 3.30

Total international 10.67 9.63 7.72

Total consolidated continuing operations 10.57 9.66 7.98

Equity affiliates 

Canada 15.85 17.64 14.82

Russia 9.48 6.80 3.94

Asia Pacific/Middle East 3.59 2.82 5.19

Total equity affiliates 9.02 7.85 5.19

Discontinued operations 12.90 10.60 11.59

Average Production Costs Per Barrel—Bitumen 

Consolidated operations—Canada $ 27.09 27.12 19.45

Equity affiliates—Canada 15.85 17.64 14.82

Taxes Other Than Income Taxes Per Barrel of Oil Equivalent 

Consolidated operations 

Alaska $ 31.75 33.11 17.65

Lower 48 3.07 3.33 3.08

United States 12.19 13.61 8.26

Canada 0.93 0.88 0.91

Europe 0.29 0.04 0.05

Asia Pacific/Middle East 4.45 6.56 3.76

Africa 0.13 0.67 0.17

Total international 1.73 2.35 1.37

Total consolidated continuing operations 7.00 7.71 4.40

Equity affiliates 

Canada 0.30 0.24 0.22

Russia 61.75 70.85 25.08

Asia Pacific/Middle East** 30.63 22.99 3.69

Total equity affiliates 20.20 23.47 20.97

Discontinued operations 1.13 0.99 0.73

Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent 

Consolidated operations 

Alaska $ 5.40 5.69 5.95

Lower 48 15.32 13.55 13.81

United States 12.16 10.84 11.02

Canada 19.01 20.33 20.38

Europe 11.47 13.80 15.58

Asia Pacific/Middle East 12.25 11.35 12.77

Africa 2.80 2.68 2.55

Total international 13.33 14.75 15.28

Total consolidated continuing operations 12.74 12.89 13.41

Equity affiliates 

Canada 10.96 10.05 10.62

Russia 3.16 4.91 4.11

Asia Pacific/Middle East** 2.90 2.92 4.83

Total equity affiliates 6.23 5.35 4.86

Discontinued operations 9.73 8.48 7.66

 * Includes bitumen.

** Certain amounts have been restated to reflect revised Results of Operations.

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Development and Exploration Activities

The following two tables summarize our net interest in productive and dry exploratory and development wells in the years ended December 31, 2012, 2011

and 2010. A “development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to

be productive. An “exploratory well” is a well drilled to find and produce crude oil or natural gas in an unknown field or a new reservoir within a proven field.

Excluded from the exploratory well count are stratigraphic-type exploratory wells, primarily relating to oil sands delineation wells located in Canada and

coalbed methane test wells located in Asia Pacific/Middle East.

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Table of Contents

Net Wells Completed Productive Dry

 

 2012 2011 2010  2012 2011 2010

Exploratory 

Consolidated operations 

Alaska * - - - - -

Lower 48 92 98 23 2 5 1

United States 92 98 23 2 5 1

Canada 5 8 15 - 3 7

Europe * 1 1 * * * 

Asia Pacific/Middle East * 1 3 - 1 1

Africa * * 1 - * * 

Other areas * - - * - -

Total consolidated operations 97 108 43 2 9 9

Equity affiliates 

Russia - - - * - -

Asia Pacific/Middle East - * - - - -

Total equity affiliates - - - - - -

Includes extension wells of: 82 98 23 - 3 1

 Productive Dry

 

 2012 2011 2010  2012 2011 2010

Development 

Consolidated operations 

Alaska 21 26 28 - - * 

Lower 48 377 350 269 * 4 2

United States 398 376 297 - 4 2

Canada 119 146 186 3 1 12

Europe 4 4 6 - - -

Asia Pacific/Middle East 11 30 5 9 - - * 

Africa 4 5 9 - - -

Total consolidated operations 536 561 557 3 5 14

Equity affiliates 

Canada 30 20 35 - - -

Russia 1 3 2 - - -

Asia Pacific/Middle East 13 9 25 - 1 -

Total equity affiliates 44 32 62 - 1 -

(1) Restated to conform to current year presentation.

(2) Excludes net stratigraphic-type exploratory wells of 213, 210 and 191 for the years ended December 31, 2012, 2011 and 2010, respectively.

(3) Includes wells drilled in areas near or offsetting current production, or in areas where well density or production history have not achieved statistical certainty of results,

primarily located in the Lower 48.

* Our total proportionate interest was less than one.

156

(1)

(2)(3)
Table of Contents

The table below represents the status of our wells drilling at December 31, 2012, and includes wells in the process of drilling or in active completion.

Wells at December 31, 2012 Productive*

 In Progress Oil Gas

 

 Gross  Net  Gross  Net  Gross  Net

Consolidated operations 

Alaska 6 3 1,741 769 37 22

Lower 48 327 191 9,613 4,563 24,833 15,523

United States 333 194 11,354 5,332 24,870 15,545

Canada 82 46 1,647 967 12,731 7,462

Europe 19 5 485 89 275 113

Asia Pacific/Middle East 34 15 353 155 112 52

Africa 52 8 1,169 205 62 12

Other areas 35 3 - - - -

Total consolidated operations 555 271 15,008 6,748 38,050 23,184

Equity affiliates 

Canada 9 5 282 141 - -

Russia - - 29 14 - -

Asia Pacific/Middle East 770 153 - - 617 137

Total equity affiliates 779 158 311 155 617 137

* Includes 415 gross and 204 net multiple completion wells.

Acreage at December 31, 2012 Thousands of Acres

 Developed Undeveloped

 Gross Net Gross Net

Consolidated operations 

Alaska 655 332 1,403 1,204

Lower 48 7,091 5,165 11,362 9,683

United States 7,746 5,497 12,765 10,887

Canada 6,615 4,313 6,327 4,379

Europe 824 243 2,045 831

Asia Pacific/Middle East 4,096 1,771 27,463 17,753

Africa 528 132 17,254 3,474

Other areas - - 9,225 3,607

Total consolidated operations 19,809 11,956 75,079 40,931

Equity affiliates 

Canada 38 15 653 278

Europe - - 506 355

Russia 16 8 619 309

Asia Pacific/Middle East 1,129 222 7,681 2,348

Total equity affiliates 1,183 245 9,459 3,290

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Costs Incurred

 Millions of Dollars

Year Ended

December 31 Alaska 

Lower

48 

Total

U.S. Canada Europe Russia 

Asia Pacific/

Middle East Africa 

Other

Areas Total

2012 

Consolidated operations 

Unproved property acquisition $ 2 562 564 14 2 - - 333 - 913

Proved property acquisition - 33 33 3 - - - - - 36

 2 595 597 17 2 

- - 333 - 949

Exploration 104 1,272 1,376 218 91 1 248 94 141 2,169 

Development 644 3,917 4,561 2,062 3,515 - 1,113 208 585 12,044

 $ 750 5,784 6,534 2,297 3,608 1 1,361 635 726 15,162 

Equity affiliates 

Unproved property acquisition $ - - - 12 - - - - - 12 

Proved property acquisition - - - - - - - - - - 

 

- - - 12 - - - - - 12 

Exploration - - - 77 11 - 52 - - 140

Development - - - 1,332 - 13 1,163 - - 2,508

 $ - 

- - 1,421 11 13 1,215 - - 2,660 

2011 

Consolidated operations 

Unproved property acquisition $ 1 577 578 145 - - - - - 723

Proved property acquisition - 10 10 - - - 36 - - 46

 1 587 588 145 

- - 36 - - 769

Exploration* 84 1,330 1,414 269 201 1 226 63 88 2,262

Development* 499 2,334 2,833 1,347 2,123 - 949 263 726 8,241

 $ 584 4,251 4,835 1,761 2,324 1 1,211 326 814 11,272

Equity affiliates 

Unproved property $ - - - - - - 484 - - 484

Proved property acquisition - - - - - - - - - - 

 

- - - - - - 484 - - 484

Exploration - - - 64 - 1 100 - - 165

Development** - - - 911 - 43 478 - - 1,432

 $ - 

- - 975 - 44 1,062 - - 2,081

 * Amounts in Lower 48 were reclassified between “Exploration” and “Development.” Total costs were unchanged.

** Asia Pacific/Middle East equity affiliates “Development” costs were restated to reflect amounts considered to be non-oil and gas producing activities.

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Year Ended Millions of Dollars

December 31

 Alaska

Lower

48 

Total

U.S. Canada Europe Russia 

Asia Pacific/

Middle East Africa 

Other

Areas Total

2010 

Consolidated operations 

Unproved property acquisition $ (26) 286 260 113 9 - - - - 382

Proved property acquisition - 100 100 1 - - - - - 101

 (26) 386 360 114 9 

- - - - 483

Exploration 119 487 606 269 144 3 356 45 143 1,566

Development 588 1,439 2,027 927 1,351 - 858 375 729 6,267

 $ 681 2,312 2,993 1,310 1,504 3 1,214 420 872 8,316

Equity affiliates 

Unproved property acquisition $ - - - 81 - 15 379 - - 475

Proved property acquisition - - - - - 173 - - - 173

 

- - - 81 - 188 379 - - 648

Exploration - - - - - 92 123 - - 215

Development - - - 621 - 751 403 - - 1,775

 $ - - 

- 702 - 1,031 905 - - 2,638

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Capitalized Costs 

At December 31 Millions of Dollars

 Alaska 

Lower

48 

Total

U.S. Canada Europe Russia 

Asia Pacific/

Middle East Africa 

Other

Areas Total

2012 

Consolidated operations 

Proved property $ 13,470 40,019 53,489 22,069 25,426 8 12,248 4,060 5,233 122,533

Unproved property 1,543 2,840 4,383 2,071 284 - 1,022 511 220 8,491

 15,013 42,859 57,872 24,140 25,710 8 13,270 4,571 5,453 131,024

Accumulated depreciation, depletion and

amortization 6,676 18,186 24,862 12,807 14,317 7 5,460 1,787 669 59,909

 $ 8,337 24,673 33,010 11,333 11,393 1 7,810 2,784 4,784 71,115

Equity affiliates 

Proved property $ - - - 7,498 - 212 4,067 - - 11,777

Unproved property - - - 1,450 53 - 6,212 - - 7,715

 

- - - 8,948 53 212 10,279 - - 19,492

Accumulated depreciation, depletion and

amortization - - - 1,046 - 183 277 - - 1,506

 $ - 

- - 7,902 53 29 10,002 - - 17,986

2011 

Consolidated operations 

Proved property $12,770 34,939 47,709 19,578 22,948 8 12,284 3,867 4,650 111,044

Unproved property 1,528 2,574 4,102 1,986 289 1 1,026 174 268 7,846

 14,298 37,513 51,811 21,564 23,237 9 13,310 4,041 4,918 118,890

Accumulated depreciation, depletion and

amortization 6,237 15,464 21,701 10,599 14,451 7 5,626 1,559 12 53,955

 $ 8,061 22,049 30,110 10,965 8,786 2 7,684 2,482 4,906 64,935

Equity affiliates 

Proved property* $ - - - 5,774 - 1,966 2,720 - - 10,460

Unproved property* - - - 1,657 - 146 7,223 - - 9,026

 

- - - 7,431 - 2,112 9,943 - - 19,486

Accumulated depreciation, depletion and

amortization - - - 764 - 1,902 184 - - 2,850

 $ - 

- - 6,667 - 210 9,759 - - 16,636

* Asia Pacific/Middle East equity affiliates “Proved property” was restated to reflect amounts considered to be non-oil and gas producing activities and to reclassify certain costs

between “Proved property” and “Unproved property.”

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities

In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices and end-of-year costs (adjusted only for existing

contractual changes), appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted

arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. For all years,

continuation of year-end economic conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new

data becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require assumptions

as to the timing of future production of proved reserves, and the timing and amount of future development costs, including dismantlement, and future

production costs, including taxes other than income taxes.

While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present

value of cash flows to be obtained from their development and production.

Discounted Future Net Cash Flows

Millions of Dollars

Alaska

Lower

48

Total

U.S. Canada Europe Russia

Asia Pacific/

Middle East Africa

Other

Areas Total

2012

Consolidated operations

Future cash inflows $141,668 71,556 213,224 36,612 73,379 - 49,234 32,009 12,012 416,470 

Less:

Future production and transportation

costs 82,663 28,447 111,110 20,995 16,180 - 15,202 4,342 3,653 171,482 

Future development costs 12,683 10,604 23,287 12,564 15,273 - 3,851 944 1,158 57,077 

Future income tax provisions 16,370 10,840 27,210 1,078 28,187 - 10,424 22,595 1,331 90,825

Future net cash flows 29,952 21,665 51,617 1,975 13,739 - 19,757 4,128 5,870 97,086 

10 percent annual discount 16,511 9,461 25,972 1,170 4,936 - 6,393 1,442 3,711 43,624 

Discounted future net cash flows $ 13,441 12,204 25,645 805 8,803 - 13,364 2,686 2,159 53,462

Equity affiliates

Future cash inflows $ - - - 72,587 - 323 47,394 - - 120,304 

Less:

Future production and transportation

costs - - - 23,967 - 245 23,689 - - 47,901 

Future development costs - - - 9,291 - 10 1,221 - - 10,522 

Future income tax provisions - - - 10,055 - 3 4,335 - - 14,393 

Future net cash flows - - - 29,274 - 6 5 18,149 - - 47,488 

10 percent annual discount - - - 18,352 - 9 8,677 - - 27,038 

Discounted future net cash flows $ - - - 10,922 - 5 6 9,472 - - 20,450 

Total company

Discounted future net cash flows $ 13,441 12,204 25,645 11,727 8,803 5 6 22,836 2,686 2,159 73,912 

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Millions of Dollars

Alaska*

Lower

48

Total

U.S. Canada Europe Russia

Asia Pacific/

Middle East** Africa

Other

Areas Total

2011

Consolidated operations

Future cash inflows $143,652 73,807 217,459 40,581 78,250 - 49,936 33,017 11,891 431,134

Less:

Future production and transportation

costs 82,773 32,766 115,539 19,148 17,166 - 14,380 4,113 3,768 174,114

Future development costs 11,385 7,519 18,904 13,393 16,986 - 3,051 885 2,080 55,299 

Future income tax provisions 16,845 11,771 28,616 2,060 29,853 - 11,967 23,825 990 97,311

Future net cash flows 32,649 21,751 54,400 5,980 14,245 - 20,538 4,194 5,053 104,410

10 percent annual discount 18,074 9,643 27,717 4,025 5,372 - 6,649 1,522 3,712 48,997

Discounted future net cash flows $ 14,575 12,108 26,683 1,955 8,873 - 13,889 2,672 1,341 55,413

Equity affiliates

Future cash inflows $ - - - 53,618 - 2,786 35,439 - - 91,843

Less:

Future production and transportation

costs - - - 16,405 - 2,765 16,814 - - 35,984

Future development costs - - - 7,163 - 36 905 - - 8,104

Future income tax provisions - - - 7,574 - 3 3,705 - - 11,282

Future net cash flows - - - 22,476 - (18) 14,015 - - 36,473

10 percent annual discount - - - 14,662 - (39) 7,217 - - 21,840

Discounted future net cash flows $ - - - 7,814 - 21 6,798 - - 14,633

Total company

Discounted future net cash flows $ 14,575 12,108 26,683 9,769 8,873 21 20,687 2,672 1,341 70,046

 * Restated to reflect revised production and income tax amounts.

** Equity affiliates were restated to reclassify amounts between “Future cash inflows” and “Future production and transportation costs.” “Discounted future net cash flows”

remains unchanged.

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Millions of Dollars

Alaska

Lower

48

Total

U.S. Canada Europe Russia

Asia Pacific/

Middle East* Africa

Other

Areas Total

2010

Consolidated operations

Future cash inflows $102,743 68,949 171,692 38,083 49,270 - 37,673 24,487 8,466 329,671

Less:

Future production and transportation

costs 57,899 29,749 87,648 16,753 12,899 - 10,480 4,142 3,007 134,929

Future development costs 8,792 7,752 16,544 11,161 10,295 - 2,226 1,133 3,050 44,409

Future income tax provisions 13,383 10,953 24,336 2,416 16,765 - 9,211 16,217 384 69,329

Future net cash flows 22,669 20,495 43,164 7,753 9,311 - 15,756 2,995 2,025 81,004

10 percent annual discount 10,723 10,046 20,769 3,890 2,597 - 4,889 1,025 2,368 35,538

Discounted future net cash flows $ 11,946 10,449 22,395 3,863 6,714 - 10,867 1,970 (343) 45,466

Equity affiliates

Future cash inflows $ - - - 47,169 - 5,610 24,225 - - 77,004

Less:

Future production and transportation

costs - - - 16,492 - 4,809 12,416 - - 33,717

Future development costs - - - 4,684 - 85 295 - - 5,064

Future income tax provisions - - - 6,649 - (80) 2,082 - - 8,651

Future net cash flows - - - 19,344 - 796 9,432 - - 29,572

10 percent annual discount - - - 13,453 - 293 4,732 - - 18,478

Discounted future net cash flows $ - - - 5,891 - 503 4,700 - - 11,094

Total company

Discounted future net cash flows $ 11,946 10,449 22,395 9,754 6,714 503 15,567 1,970 (343) 56,560

 * Equity affiliates were restated to reclassify amounts between “Future cash inflows” and “Future production and transportation costs.” “Discounted future net cash flows”

remains unchanged.

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Sources of Change in Discounted Future Net Cash Flows

 Millions of Dollars

 Consolidated Operations Equity Affiliates Total Company

 2012 2011* 2010 2012 2011** 2010 2012 2011 2010

Discounted future net cash flows at the beginning of the

year $ 55,413 45,466 30,393 14,633 11,094 11,881 70,046 56,560 42,274 

Changes during the year 

Revenues less production and transportation costs

for the year (22,578) (24,223) (22,296) (2,126) (1,921) (3,083) (24,704) (26,144) (25,379) 

Net change in prices and production and

transportation costs (5,684) 33,878 39,532 912 4,644 3,478 (4,772) 38,522 43,010 

Extensions, discoveries and improved recovery, less

estimated future costs 11,192 8,555 4,517 1,963 832 297 13,155 9,387 4,814 

Development costs for the year 10,944 8,428 5,617 2,438 1,488 1,758 13,382 9,916 7,375 

Changes in estimated future development costs (9,832) (8,374) (2,917) (1,731) (1,508) (129) (11,563) (9,882) (3,046) 

Purchases of reserves in place, less estimated future

costs 16 19 19 - - - 16 19 19 

Sales of reserves in place, less estimated future costs (913) (390) (3,729) (139) (234) (5,405) (1,052) (624) (9,134) 

Revisions of previous quantity estimates 2,047 (1,606) 3,062 3,952 491 372 5,999 (1,115) 3,434 

Accretion of discount 10,072 7,710 5,000 1,788 1,284 1,404 11,860 8,994 6,404 

Net change in income taxes 2,785 (14,050) (13,732) (1,240) (1,537) 521 1,545 (15,587) (13,211) 

Total changes (1,951) 9,947 15,073 5,817 3,539 (787) 3,866 13,486 14,286 

Discounted future net cash flows

at year end $ 53,462 55,413 45,466 20,450 14,633 11,094 73,912 70,046 56,560 

 * Restated to reflect revised production and income tax amounts.

** Certain amounts in Asia Pacific/Middle East equity affiliates have been restated to reflect revised natural gas prices and to reclassify amounts previously considered non-oil and

gas producing activities.

• The net change in prices and production and transportation costs is the beginning-of-year reserve-production forecast multiplied by the net annual

change in the per-unit sales price and production and transportation cost, discounted at 10 percent.

• Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the

applicable reserve quantities for the year multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent.

• The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production, transportation and development costs.

• The net change in income taxes is the annual change in the discounted future income tax provisions.

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Selected Quarterly Financial Data (Unaudited) 

 Millions of Dollars 

 Sales and

Other

Operating

Revenues*

 Income From

Continuing

Operations Before

Income Taxes*

 

Net

Income

 Net Income

Attributable

to

ConocoPhillips

 Per Share of Common Stock

 

Net Income Attributable to

ConocoPhillips

 Basic Diluted

2012 

First $ 14,593 4,265 2,955 2,937 2.29 2.27

Second 13,664 3,945 2,289 2,267 1.82 1.80

Third 14,141 3,591 1,813 1,798 1.47 1.46

Fourth 15,569 3,622 1,441 1,426 1.16 1.16

2011 

First $ 15,398 4,551 3,042 3,028 2.11 2.09

Second 16,735 4,256 3,419 3,402 2.43 2.41

Third 16,108 3,401 2,631 2,616 1.93 1.91

Fourth 15,955 3,188 3,410 3,390 2.58 2.56

*Prior periods have been restated as a result of discontinued operations.

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Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada

Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent

owned by ConocoPhillips. ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding

Company II are indirect, 100 percent owned subsidiaries of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and

unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and

ConocoPhillips Canada Funding Company II, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally

guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has

fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and

several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:

• ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and

ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).

• All other nonguarantor subsidiaries of ConocoPhillips.

• The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.

In February 2009, we filed a universal shelf registration statement with the SEC under which ConocoPhillips, as a well-known seasoned issuer, has the

ability to issue and sell an indeterminate amount of various types of debt and equity securities, with certain debt securities guaranteed by ConocoPhillips

Company. Also as part of that registration statement, ConocoPhillips Trust I and ConocoPhillips Trust II have the ability to issue and sell preferred trust

securities, guaranteed by ConocoPhillips. ConocoPhillips Trust I and ConocoPhillips Trust II have not issued any trust-preferred securities under this

registration statement, and thus have no assets or liabilities. Accordingly, columns for these two trusts are not included in the condensed consolidating

financial information.

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.

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Millions of Dollars

Year Ended December 31, 2012

Income Statement ConocoPhillips

ConocoPhillips

Company

ConocoPhillips

Australia Funding

Company

ConocoPhillips

Canada Funding

Company I

ConocoPhillips

Canada Funding

Company II

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Revenues and Other Income

Sales and other operating revenues $ - 17,768 - - - 40,199 - 57,967 

Equity in earnings of affiliates 8,858 10,126 - - - 1,890 (18,963) 1,911 

Gain on dispositions - 2 - - - 1,655 - 1,657 

Other income (loss) (76) 177 - - - 368 - 469 

Intercompany revenues 61 1,013 46 90 34 4,526 (5,770) - 

Total Revenues and Other Income 8,843 29,086 46 90 34 48,638 (24,733) 62,004 

Costs and Expenses

Purchased commodities - 15,680 - - - 13,000 (3,448) 25,232 

Production and operating expenses - 1,304 - - - 5,512 (23) 6,793 

Selling, general and administrative expenses 12 845 - - - 259 (10) 1,106 

Exploration expenses - 402 - - - 1,098 - 1,500 

Depreciation, depletion and amortization - 807 - - - 5,773 - 6,580 

Impairments - 8 - - - 672 - 680 

Taxes other than income taxes - 264 - - - 3,282 - 3,546 

Accretion on discounted liabilities - 53 - - - 341 - 394 

Interest and debt expense 2,218 316 42 77 32 313 (2,289) 709 

Foreign currency transaction (gains) losses (19) 19 - 13 22 6 - 41 

Total Costs and Expenses 2,211 19,698 42 90 54 30,256 (5,770) 46,581 

Income (loss) from continuing operations before

income taxes 6,632 9,388 4 - (20) 18,382 (18,963) 15,423 

Provision for income taxes (779) 530 1 8 (2) 8,184 - 7,942 

Income (Loss) From Continuing Operations 7,411 8,858 3 (8) (18) 10,198 (18,963) 7,481 

Income from discontinued operations 1,017 1,017 - - - 777 (1,794) 1,017 

Net income (loss) 8,428 9,875 3 (8) (18) 10,975 (20,757) 8,498 

Less: net income attributable to noncontrolling

interests - - - - - (70) - (70) 

Net Income (Loss) Attributable to ConocoPhillips $ 8,428 9,875 3 (8) (18) 10,905 (20,757) 8,428 

Comprehensive Income (Loss) Attributable to

ConocoPhillips $ 9,055 10,502 3 27 (4) 11,140 (21,668) 9,055 

Income Statement Year Ended December 31, 2011

Revenues and Other Income

Sales and other operating revenues $ - 20,606 - - - 43,590 - 64,196 

Equity in earnings of affiliates 8,164 8,245 - - - 1,293 (16,463) 1,239 

Gain on dispositions - 261 - - - 109 - 370 

Other income - 98 - - - 166 - 264 

Intercompany revenues 4 1,346 46 91 35 2,683 (4,205) - 

Total Revenues and Other Income 8,168 30,556 46 91 35 47,841 (20,668) 66,069 

Costs and Expenses

Purchased commodities - 17,944 - - - 14,287 (2,434) 29,797 

Production and operating expenses - 1,126 - - - 5,363 (63) 6,426 

Selling, general and administrative expenses 13 607 - - - 254 (9) 865 

Exploration expenses - 333 - - - 705 - 1,038 

Depreciation, depletion and amortization - 867 - - - 5,960 - 6,827 

Impairments - 38 - - - 283 - 321 

Taxes other than income taxes - 292 - - - 3,707 - 3,999 

Accretion on discounted liabilities - 48 - - - 374 - 422 

Interest and debt expense 1,594 448 42 77 32 460 (1,699) 954 

Foreign currency transaction (gains) losses - (16) - (10) (35) 85 - 24 

Total Costs and Expenses 1,607 21,687 42 67 (3) 31,478 (4,205) 50,673 

Income from continuing operations before income

taxes 6,561 8,869 4 24 38 16,363 (16,463) 15,396 

Provision for income taxes (561) 705 1 (1) 12 8,052 - 8,208 

Income From Continuing Operations 7,122 8,164 3 25 26 8,311 (16,463) 7,188 

Income from discontinued operations 5,314 5,314 - - - 4,868 (10,182) 5,314 

Net income 12,436 13,478 3 25 26 13,179 (26,645) 12,502 

Less: net income attributable to noncontrolling

interests - - - - - (66) - (66) 

Net Income Attributable to ConocoPhillips $ 12,436 13,478 3 25 26 13,113 (26,645) 12,436 

Comprehensive Income (Loss) Attributable to

ConocoPhillips $ 10,749 11,791 3 (6) 14 11,901 (23,703) 10,749 

167
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Millions of Dollars

Year Ended December 31, 2010

Income Statement ConocoPhillips

ConocoPhillips

Company

ConocoPhillips

Australia Funding

Company

ConocoPhillips

Canada Funding

Company I

ConocoPhillips

Canada Funding

Company II

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Revenues and Other Income

Sales and other operating revenues $ - 21,531 - - - 34,684 - 56,215 

Equity in earnings of affiliates 10,865 11,237 - - - 1,286 (22,012) 1,376 

Gain on dispositions - 370 - - - 5,193 - 5,563 

Other income (loss) 1 191 - - (28) 17 - 181 

Intercompany revenues 5 661 46 86 66 3,886 (4,750) - 

Total Revenues and Other Income 10,871 33,990 46 86 38 45,066 (26,762) 63,335 

Costs and Expenses

Purchased commodities - 18,587 - - - 9,843 (3,576) 24,854 

Production and operating expenses - 1,328 - - - 4,923 (24) 6,227 

Selling, general and administrative expenses 12 602 - - - 222 (27) 809 

Exploration expenses - 247 - - - 878 - 1,125 

Depreciation, depletion and amortization - 978 - - - 7,026 - 8,004 

Impairments - - - - - 81 - 81 

Taxes other than income taxes - 293 - - - 2,495 - 2,788 

Accretion on discounted liabilities - 41 - - - 368 - 409 

Interest and debt expense 946 503 42 77 45 677 (1,123) 1,167 

Foreign currency transaction (gains) losses - 23 - 47 50 (124) - (4) 

Total Costs and Expenses 958 22,602 42 124 95 26,389 (4,750) 45,460 

Income (loss) from continuing operations

before income taxes 9,913 11,388 4 (38) (57) 18,677 (22,012) 17,875 

Provision for income taxes (333) 523 1 7 (6) 7,378 - 7,570 

Income (Loss) From Continuing

Operations 10,246 10,865 3 (45) (51) 11,299 (22,012) 10,305 

Income from discontinued operations 1,112 1,112 - - - 1,348 (2,460) 1,112 

Net income (loss) 11,358 11,977 3 (45) (51) 12,647 (24,472) 11,417 

Less: net income attributable to

noncontrolling interests - - - - - (59) - (59) 

Net Income (Loss) Attributable to

ConocoPhillips $ 11,358 11,977 3 (45) (51) 12,588 (24,472) 11,358 

Comprehensive Income (Loss) Attributable

to ConocoPhillips $ 13,066 13,685 3 24 (19) 14,279 (27,972) 13,066 

168
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Millions of Dollars

At December 31, 2012

Balance Sheet ConocoPhillips

ConocoPhillips

Company

ConocoPhillips

Australia Funding

Company

ConocoPhillips

Canada Funding

Company I

ConocoPhillips

Canada Funding

Company II

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Assets

Cash and cash equivalents $ 2 12 6 50 2 3,546 - 3,618

Restricted cash 748 - - - - - - 748

Accounts and notes receivable 64 6,247 - - - 7,958 (5,087) 9,182

Inventories - 57 - - - 908 - 965

Prepaid expenses and other current assets 19 847 - 1 - 8,609 - 9,476

Total Current Assets 833 7,163 6 51 2 21,021 (5,087) 23,989

Investments, loans and long-term receivables* 80,910 114,314 759 1,455 578 44,739 (217,749) 25,006

Net properties, plants and equipment - 8,771 - - - 58,492 - 67,263

Intangibles - - - - - 4 - 4

Other assets 55 216 - 2 3 606 - 882

Total Assets $ 81,798 130,464 765 1,508 583 124,862 (222,836) 117,144

Liabilities and Stockholders’ Equity

Accounts payable $ - 9,067 - 4 1 6,028 (5,087) 10,013

Short-term debt (5) 4 750 - - 206 - 955

Accrued income and other taxes - 104 - 3 - 3,259 - 3,366

Employee benefit obligations - 485 - - - 257 - 742

Other accruals 209 636 9 15 4 1,494 - 2,367

Total Current Liabilities 204 10,296 759 22 5 11,244 (5,087) 17,443

Long-term debt 9,453 5,215 - 1,250 499 4,353 - 20,770

Asset retirement obligations and accrued

environmental costs - 1,250 - - - 7,697 - 8,947

Joint venture acquisition obligation - - - - - 2,810 - 2,810

Deferred income taxes 15 598 - 16 7 12,549 - 13,185

Employee benefit obligations - 2,464 - - - 882 - 3,346

Other liabilities and deferred credits* 30,938 19,916 - 117 50 21,174 (69,979) 2,216

Total Liabilities 40,610 39,739 759 1,405 561 60,709 (75,066) 68,717

Retained earnings 28,815 24,041 4 (78) (73) 30,778 (48,149) 35,338

Other common stockholders’ equity 12,373 66,684 2 181 95 32,935 (99,621) 12,649

Noncontrolling interests - - - - - 440 - 440

Total Liabilities and Stockholders’ Equity $ 81,798 130,464 765 1,508 583 124,862 (222,836) 117,144

Balance Sheet At December 31, 2011

Assets

Cash and cash equivalents $ - 2,028 1 37 1 3,713 - 5,780

Short-term investments - - - - - 581 - 581

Accounts and notes receivable 60 9,186 - - - 20,898 (13,618) 16,526

Inventories - 2,239 - - - 2,392 - 4,631

Prepaid expenses and other current assets 22 1,090 - 1 - 1,587 - 2,700

Total Current Assets 82 14,543 1 38 1 29,171 (13,618) 30,218

Investments, loans and long-term receivables* 96,284 135,618 760 1,417 565 59,651 (260,512) 33,783

Net properties, plants and equipment - 19,595 - - - 64,585 - 84,180

Goodwill - 3,332 - - - - - 3,332

Intangibles - 722 - - - 23 - 745

Other assets 64 301 - 2 3 602 - 972

Total Assets $ 96,430 174,111 761 1,457 569 154,032 (274,130) 153,230

Liabilities and Stockholders’ Equity

Accounts payable $ 10 18,747 - 1 1 14,512 (13,618) 19,653

Short-term debt 892 27 - - - 94 - 1,013

Accrued income and other taxes - 315 - 2 - 3,903 - 4,220

Employee benefit obligations - 835 - - - 276 - 1,111

Other accruals 244 634 9 14 6 1,164 - 2,071

Total Current Liabilities 1,146 20,558 9 17 7 19,949 (13,618) 28,068

Long-term debt 10,951 3,599 749 1,250 498 4,563 - 21,610

Asset retirement obligations and accrued

environmental costs - 1,766 - - - 7,563 - 9,329

Joint venture acquisition obligation - - - - - 3,582 - 3,582

Deferred income taxes (5) 3,982 - 11 9 14,043 - 18,040

Employee benefit obligations - 3,092 - - - 976 - 4,068

Other liabilities and deferred credits* 25,959 40,479 - 104 29 20,047 (83,834) 2,784

Total Liabilities 38,051 73,476 758 1,382 543 70,723 (97,452) 87,481

Retained earnings 42,550 34,921 1 (70) (55) 29,821 (58,119) 49,049

Other common stockholders’ equity 15,829 65,714 2 145 81 52,978 (118,559) 16,190

Noncontrolling interests - - - - - 510 - 510

Total Liabilities and Stockholders’ Equity $ 96,430 174,111 761 1,457 569 154,032 (274,130) 153,230

 * Includes intercompany loans.

169
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Millions of Dollars

Statement of Cash Flows Year Ended December 31, 2012

ConocoPhillips

ConocoPhillips

Company

ConocoPhillips

Australia Funding

Company

ConocoPhillips

Canada Funding

Company I

ConocoPhillips

Canada Funding

Company II

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Cash Flows From Operating Activities

Net cash provided by continuing operating

activities $ 3,947 14,992 5 13 1 7,750 (13,250) 13,458 

Net cash provided by (used in) discontinued

operations - 479 - - - (15) - 464 

Net Cash Provided by Operating Activities 3,947 15,471 5 13 1 7,735 (13,250) 13,922 

Cash Flows From Investing Activities

Capital expenditures and investments (317) (5,994) - - - (12,433) 4,572 (14,172) 

Proceeds from asset dispositions 14 937 - - - 2,126 (945) 2,132 

Net purchases of short-term investments - - - - - 597 - 597 

Long-term advances/loans—related parties - (85) - - - (2,920) 3,005 - 

Collection of advances/loans—related parties - 150 - - - 5,884 (5,920) 114 

Other - 442 - - - 379 - 821 

Net cash used in continuing investing activities (303) (4,550) - - - (6,367) 712 (10,508) 

Net cash provided by (used in) discontinued

operations - (232) - - - 7,213 (8,100) (1,119) 

Net Cash Provided by (Used in) Investing

Activities (303) (4,782) - - - 846 (7,388) (11,627) 

Cash Flows From Financing Activities

Issuance of debt - 5,033 - - - 69 (3,106) 1,996 

Repayment of debt (2,474) (14,033) - - - (179) 14,121 (2,565) 

Special cash distribution from Phillips 66 7,818 - - - - - - 7,818 

Change in restricted cash (748) - - - - - - (748) 

Issuance of company common stock 138 - - - - - - 138 

Repurchase of company common stock (5,098) - - - - - - (5,098) 

Dividends paid on common stock (3,278) - - - - (7,909) 7,909 (3,278) 

Other - 118 - - - (1,771) 928 (725) 

Net cash used in continuing financing activities (3,642) (8,882) - - - (9,790) 19,852 (2,462) 

Net cash provided by (used in) discontinued

operations - (3,786) - - - 981 786 (2,019) 

Net Cash Used in Financing Activities (3,642) (12,668) - - - (8,809) 20,638 (4,481) 

Effect of Exchange Rate Changes on Cash and

Cash Equivalents - (37) - - - 61 - 24 

Net Change in Cash and Cash Equivalents 2 (2,016) 5 13 1 (167) - (2,162) 

Cash and cash equivalents at beginning of

period - 2,028 1 37 1 3,713 - 5,780 

Cash and Cash Equivalents at End of Period $ 2 12 6 50 2 3,546 - 3,618 

Statement of Cash Flows Year Ended December 31, 2011

Cash Flows From Operating Activities

Net cash provided by (used in) continuing

operating activities $ 14,669 (1,805) 1 12 (7) 4,427 (3,344) 13,953 

Net cash provided by (used in) discontinued

operations - (2,359) - - - 8,052 - 5,693 

Net Cash Provided by (Used in) Operating

Activities 14,669 (4,164) 1 12 (7) 12,479 (3,344) 19,646 

Cash Flows From Investing Activities

Capital expenditures and investments - (1,504) - - - (9,710) - (11,214) 

Proceeds from asset dispositions - 318 - - - 1,874 - 2,192 

Net purchases of short-term investments - - - - - 400 - 400 

Long-term advances/loans—related parties - (916) - (4) - (4,553) 5,473 - 

Collection of advances/loans—related parties - 993 - - - 8,340 (9,235) 98 

Other - 6 - - - 44 - 50 

Net cash used in continuing investing activities - (1,103) - (4) - (3,605) (3,762) (8,474) 

Net cash provided by (used in) discontinued

operations - 2,376 - - - (9,117) 8,200 1,459 

Net Cash Provided by (Used in) Investing

Activities - 1,273 - (4) - (12,722) 4,438 (7,015) 

Cash Flows From Financing Activities

Issuance of debt - 12,758 - - 4 827 (13,589) - 

Repayment of debt - (8,657) - - - (1,426) 9,149 (934) 

Issuance of company common stock 96 - - - - - - 96 

Repurchase of company common stock (11,123) - - - - - - (11,123) 

Dividends paid on common stock (3,633) - - - - (3,051) 3,052 (3,632) 

Other (9) 119 - - - (794) - (684) 

Net cash provided by (used in) continuing

financing activities (14,669) 4,220 - - 4 (4,444) (1,388) (16,277) 

Net cash used in discontinued operations - (18) - - - (304) 294 (28) 

Net Cash Provided by (Used in) Financing

Activities (14,669) 4,202 - - 4 (4,748) (1,094) (16,305) 

Effect of Exchange Rate Changes on Cash and

Cash Equivalents - (1) - - - 1 - - 

Net Change in Cash and Cash Equivalents - 1,310 1 8 (3) (4,990) - (3,674) 

Cash and cash equivalents at beginning of

period - 718 - 29 4 8,703 - 9,454 

Cash and Cash Equivalents at End of Period $ - 2,028 1 37 1 3,713 - 5,780 
170
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Millions of Dollars

Statement of Cash Flows Year Ended December 31, 2010

ConocoPhillips

ConocoPhillips

Company

ConocoPhillips

Australia Funding

Company

ConocoPhillips

Canada Funding

Company I

ConocoPhillips

Canada Funding

Company II

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Cash Flows From Operating Activities

Net cash provided by (used in) continuing

operating activities $ 7,901 1,962 - 11 (3) 6,655 (2,513) 14,013 

Net cash provided by discontinued operations - 349 - - - 2,683 - 3,032 

Net Cash Provided by (Used in) Operating

Activities 7,901 2,311 - 11 (3) 9,338 (2,513) 17,045 

Cash Flows From Investing Activities

Capital expenditures and investments - (1,120) - - - (6,738) 323 (7,535) 

Proceeds from asset dispositions - 789 - - - 14,020 (99) 14,710 

Net sales of short-term investments - - - - - (982) - (982) 

Long-term advances/loans—related parties - (135) - - - (2,284) 2,301 (118) 

Collection of advances/loans—related parties - 87 - - 384 1,379 (1,755) 95 

Other - 28 - - - 190 - 218 

Net cash provided by (used in) continuing

investing activities - (351) - - 384 5,585 770 6,388 

Net cash used in discontinued operations - (931) - - - (792) - (1,723) 

Net Cash Provided by (Used in) Investing

Activities - (1,282) - - 384 4,793 770 4,665 

Cash Flows From Financing Activities

Issuance of debt - 2,159 - - - 260 (2,301) 118 

Repayment of debt (990) (2,642) - - (378) (3,039) 1,755 (5,294) 

Issuance of company common stock 133 - - - - - - 133 

Repurchase of company common stock (3,866) - - - - - - (3,866) 

Dividends paid (3,175) - - - - (2,666) 2,666 (3,175) 

Other (3) 52 - - - (782) 27 (706) 

Net cash used in continuing financing activities (7,901) (431) - - (378) (6,227) 2,147 (12,790) 

Net cash provided by (used in) discontinued

operations - (18) - - - 240 (251) (29) 

Net Cash Used in Financing Activities (7,901) (449) - - (378) (5,987) 1,896 (12,819) 

Effect of Exchange Rate Changes on Cash and

Cash Equivalents - 16 - - - 5 - 21 

Net Change in Cash and Cash Equivalents - 596 - 11 3 8,149 153 8,912 

Cash and cash equivalents at beginning of

period - 122 - 18 1 554 (153) 542 

Cash and Cash Equivalents at End of Period $ - 718 - 29 4 8,703 - 9,454 

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities

Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange

Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal

financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of December 31, 2012, with the participation of our management,

our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance and Chief Financial Officer (principal

financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule

13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial

Officer concluded that our disclosure controls and procedures were operating effectively as of December 31, 2012.

There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the period covered by this report that

have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

This report is included in Item 8 on page 72 and is incorporated herein by reference.

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

This report is included in Item 8 on page 74 and is incorporated herein by reference.

Item 9B. OTHER INFORMATION

None.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding our executive officers appears in Part I of this report on pages 28 and 29.

Code of Business Ethics and Conduct for Directors and Employees

We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics), including our principal executive officer, principal financial

officer, principal accounting officer and persons performing similar functions. We have posted a copy of our Code of Ethics on the “Corporate Governance”

section of our Internet Web site at www.conocophillips.com (within the Investor Relations>Governance section) . Any waivers of the Code of Ethics must be

approved, in advance, by our full Board of Directors. Any amendments to, or waivers from, the Code of Ethics that apply to our executive officers and

directors will be posted on the “Corporate Governance” section of our Internet Web site.

All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our 2013 Annual Meeting of Stockholders, to be filed

pursuant to Regulation 14A on or before April 30, 2013, and is incorporated herein by reference.*

Item 11. EXECUTIVE COMPENSATION

Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2013 Annual Meeting of Stockholders, to be filed pursuant to

Regulation 14A on or before April 30, 2013, and is incorporated herein by reference.*

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER

MATTERS

Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2013 Annual Meeting of Stockholders, to be filed pursuant to

Regulation 14A on or before April 30, 2013, and is incorporated herein by reference.*

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2013 Annual Meeting of Stockholders, to be filed pursuant to

Regulation 14A on or before April 30, 2013, and is incorporated herein by reference.*

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2013 Annual Meeting of Stockholders, to be filed pursuant to

Regulation 14A on or before April 30, 2013, and is incorporated herein by reference.*

*Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2013 Proxy Statement are not

deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements and Supplementary Data

The financial statements and supplementary information listed in the Index to Financial Statements, which appears on page 71, are filed as part

of this annual report.

2. Financial Statement Schedules

Schedule II—Valuation and Qualifying Accounts, appears below. All other schedules are omitted because they are not required, not significant,

not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements.

3. Exhibits

The exhibits listed in the Index to Exhibits, which appears on pages 161 through 166 are filed as part of this annual report.

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS (Consolidated)

ConocoPhillips

 Millions of Dollars

Description 

Balance at

January 1 

Charged to

Expense Other(a) Deductions

Balance at

December 31

2012 

Deducted from asset accounts: 

Allowance for doubtful accounts and notes receivable $ 30 (4) (13) (3)(b) 10

Deferred tax asset valuation allowance 1,487 369 (447) (64) 1,345

Included in other liabilities: 

Restructuring accruals 48 9 (5) (35)(c) 17

2011 

Deducted from asset accounts: 

Allowance for doubtful accounts and notes receivable $ 32 2 — (4)(b) 30

Deferred tax asset valuation allowance 1,400 174 (31) (56) 1,487

Included in other liabilities: 

Restructuring accruals 105 25 (1) (81)(c) 48

2010 

Deducted from asset accounts: 

Allowance for doubtful accounts and notes receivable $ 76 (31) (1) (12)(b) 32

Deferred tax asset valuation allowance 1,540 414 (12) (542) 1,400

Included in other liabilities: 

Restructuring accruals 73 78 1 (47)(c) 105

(a)Represents acquisitions/dispositions/revisions and the effect of translating foreign financial statements.

(b)Amounts charged off less recoveries of amounts previously charged off.

(c)Benefit payments.

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CONOCOPHILLIPS

INDEX TO EXHIBITS

Exhibit

Number

 Description

2.1

 

Separation and Distribution Agreement Between ConocoPhillips and Phillips 66, dated April 26, 2012 (incorporated by reference to Exhibit

2.1 to the Current Report of ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).

3.1

 

Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Quarterly Report of ConocoPhillips on

Form 10-Q for the quarterly period ended June 30, 2008; File No. 001-32395).

3.2

 

Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips (incorporated by reference to Exhibit 3.2 to the

Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987).

3.3

 

Amended and Restated By-Laws of ConocoPhillips, as amended and restated as of February 10, 2012 (incorporated by reference to Exhibit

3.1 to the Current Report of ConocoPhillips on Form 8-K filed on February 16, 2012; File No. 001-32395).

 

ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total amount of securities authorized does not

exceed 10 percent of the total assets of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of

Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon request.

10.1

 

1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the Annual Report of ConocoPhillips on

Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.2

 

1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the Annual Report of ConocoPhillips on

Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.3

 

Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.13 to the Annual Report of

ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.4

 

Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(g) to the Annual Report of

ConocoPhillips Company on Form 10-K for the year ended December 31, 1999; File No. 1-720).

10.5

 

Amendment and Restatement of ConocoPhillips Supplemental Executive Retirement Plan, dated April 19, 2012 (incorporated by reference to

Exhibit 10.14 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).

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Exhibit

Number

 Description

10.6

 

Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.18 to the Annual Report of

ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.7

 

Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.19 to the Annual Report of ConocoPhillips on

Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.8

 

Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by reference to Exhibit 10.10 to the Annual Report of

ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).

10.9

 

Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.22 to the Annual Report of

ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.10

 

Amendment and Restatement of ConocoPhillips Key Employee Supplemental Retirement Plan, dated April 19, 2012 (incorporated by reference

to Exhibit 10.13 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).

10.11.1

 

Amendment and Restatement of Defined Contribution Make-Up Plan of ConocoPhillips—Title I, dated April 19, 2012 (incorporated by

reference to Exhibit 10.11.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).

10.11.2

 

Amendment and Restatement of Defined Contribution Make-Up Plan of ConocoPhillips—Title II, dated April 19, 2012 (incorporated by

reference to Exhibit 10.11.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).

10.11.3

 

First Amendment to the Defined Contribution Make-Up Plan of ConocoPhillips—Title II, dated October 11, 2012 (incorporated by reference to

Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30, 2012; File No. 001-32395).

10.12

 

2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.26 to the Annual Report of

ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.13

 

Amendment and Restatement of 1998 Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Exhibit 10.27 to

the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.14

 

Amendment and Restatement of 1998 Key Employee Stock Performance Plan of ConocoPhillips (incorporated by reference to Exhibit 10.28 to

the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.15

 

Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by reference to Exhibit 10.17 to the Annual Report of

ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).

10.16

 

ConocoPhillips Form Indemnity Agreement with Directors (incorporated by reference to Exhibit 10.34 to the Annual Report of ConocoPhillips on

Form 10-K for the year ended December 31, 2002; File No. 000-49987).

176
Table of Contents

Exhibit

Number

 Description

10.17.1

 

Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of the Annual Report of

ConocoPhillips Holding Company on Form 10-K for the year ended December 31, 1999; File No. 001-14521).

10.17.2

 

Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to Exhibit 10.39.1 to the Annual Report of

ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).

10.18.1

 

ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to the Annual Report of ConocoPhillips on Form

10-K for the year ended December 31, 2003; File No. 000-49987).

10.18.2

 

First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10 to the Quarterly

Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008; File No. 001-32395).

10.19

 

ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to Exhibit 10.41 to the Annual Report of

ConocoPhillips on Form 10-K for the year ended December 31, 2003; File No. 000-49987).

10.20.1

 

Amendment and Restatement of Key Employee Deferred Compensation Plan of ConocoPhillips—Title I, dated April 19, 2012 (incorporated by

reference to Exhibit 10.12.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).

10.20.2

 

Amendment and Restatement of Key Employee Deferred Compensation Plan of ConocoPhillips—Title II, dated April 19, 2012 (incorporated by

reference to Exhibit 10.12.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).

10.20.3

 

First Amendment to the Key Employee Deferred Compensation Plan of ConocoPhillips—Title II (incorporated by reference to Exhibit 10.20.3 to

the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2010; File No. 001-32395).

10.20.4

 

Second Amendment to the Key Employee Deferred Compensation Plan of ConocoPhillips—Title II (incorporated by reference to Exhibit 10.20.4

to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2010; File No. 001-32395).

10.21

 

Amendment and Restatement of ConocoPhillips Key Employee Change in Control Severance Plan, dated October 11, 2012 (incorporated by

reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30, 2012; File No. 001-

32395).

10.22

 

ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.23 to the Annual Report of ConocoPhillips on Form 10-K for

the year ended December 31, 2008; File No. 001-32395).

10.23.1

 

2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Appendix C of ConocoPhillips’ Proxy

Statement on Schedule 14A relating to the 2004 Annual Meeting of Shareholders; File No. 000-49987).

10.23.2

 

Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights Program under the 2004 Omnibus Stock and

Performance Incentive Plan of ConocoPhillips (incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K

for the year ended December 31, 2008; File No. 001-32395).

177
Table of Contents

Exhibit

Number

 Description

10.23.3

 

Form of Performance Share Unit Award Agreement under the Performance Share Program under the 2004 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips (incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year

ended December 31, 2008; File No. 001-32395).

10.24

 

Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7, 2007 (incorporated by reference to Exhibit 10.30

to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2007; File No. 001-32395).

10.25

 

2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Appendix A of ConocoPhillips’ Proxy

Statement on Schedule 14A relating to the 2009 Annual Meeting of Shareholders; File No. 001-32395).

10.26.1

 

2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Appendix A of ConocoPhillips’ Proxy

Statement on Schedule 14A relating to the 2011 Annual Meeting of Shareholders; File No. 001-32395).

10.26.2

 

Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights Program under the 2011 Omnibus Stock and

Performance Incentive Plan of ConocoPhillips, effective February 9, 2012 (incorporated by reference to Exhibit 10 to the Quarterly Report of

ConocoPhillips on Form 10-Q for the quarter ended March 31, 2012; File No. 001-32395).

10.26.3

 

Form of Restricted Stock Units Agreement under the Restricted Stock Program under the 2011 Omnibus Stock and Performance Incentive Plan

of ConocoPhillips, effective April 4, 2012 (incorporated by reference to Exhibit 10.6 to the Quarterly Report of ConocoPhillips on Form 10-Q

for the quarter ended June 30, 2012; File No. 001-32395).

10.26.4

 

Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011 Omnibus Stock and Performance Incentive

Plan of ConocoPhillips, effective May 8, 2012 (incorporated by reference to Exhibit 10.7 to the Quarterly Report of ConocoPhillips on Form

10-Q for the quarter ended June 30, 2012; File No. 001-32395).

10.26.5*

 

Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011 Omnibus Stock and Performance Incentive

Plan of ConocoPhillips, dated September 18, 2012.

10.26.6*

 

Form of Performance Share Unit Agreement under the Restricted Stock Program under the 2011 Omnibus Stock and Performance Incentive

Plan of ConocoPhillips, dated February 5, 2013.

10.26.7*

 

Form of Performance Share Unit Agreement—Canada under the Restricted Stock Program under the 2011 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips, dated February 5, 2013.

10.26.8*

 

Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011 Omnibus Stock and Performance Incentive

Plan of ConocoPhillips, dated February 5, 2013.

10.26.9*

 

Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights Program under the 2011 Omnibus Stock and

Performance Incentive Plan of ConocoPhillips, dated February 5, 2013.

10.27

 

Amendment and Restatement of Annex to Nonqualified Deferred Compensation Arrangements of ConocoPhillips, dated April 19, 2012

(incorporated by reference to Exhibit 10.8 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File

No. 001-32395).

178
Table of Contents

Exhibit

Number

 Description

10.28

 

Amendment, Change of Sponsorship, and Restatement of Certain Nonqualified Deferred Compensation Plans of ConocoPhillips, dated

April 19, 2012 (incorporated by reference to Exhibit 10.10 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended

June 30, 2012; File No. 001-32395).

10.29

 

Amendment and Restatement of the Burlington Resources Inc. Management Supplemental Benefits Plan, dated April 19, 2012 (incorporated

by reference to Exhibit 10.9 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-

32395).

10.30

 

Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012 (incorporated by reference to Exhibit

10.1 to the Current Report of ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).

10.31

 

Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012 (incorporated by

reference to Exhibit 10.2 to the Current Report of ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).

10.32

 

Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012 (incorporated by reference to Exhibit 10.3 to the

Current Report of ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).

10.33

 

Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 12, 2012 (incorporated by reference to Exhibit 10.4 to the

Current Report of ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).

10.34

 

Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012 (incorporated by reference to Exhibit 10.5 to

the Current Report of ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).

10.35

 

ConocoPhillips Clawback Policy dated October 3, 2012 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of ConocoPhillips

on Form 10-Q for the quarter ended September 30, 2012; File No. 001-32395).

12* Computation of Ratio of Earnings to Fixed Charges.

21* List of Subsidiaries of ConocoPhillips.

23.1* Consent of Ernst & Young LLP.

23.2* Consent of DeGolyer and MacNaughton.

31.1* Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2* Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32* Certifications pursuant to 18 U.S.C. Section 1350.

99* Report of DeGolyer and MacNaughton.

179
Table of Contents

Exhibit

Number

 Description

101.INS* XBRL Instance Document.

101.SCH* XBRL Schema Document.

101.CAL* XBRL Calculation Linkbase Document.

101.DEF* XBRL Definition Linkbase Document.

101.LAB* XBRL Labels Linkbase Document.

101.PRE* XBRL Presentation Linkbase Document.

* Filed herewith.

180
Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf

by the undersigned, thereunto duly authorized.

CONOCOPHILLIPS

February 19, 2013 /s/ Ryan M. Lance

Ryan M. Lance

Chairman of the Board of Directors

and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 19, 2013, on behalf of the registrant by the

following officers in the capacity indicated and by a majority of directors.

Signature Title

/s/ Ryan M. Lance Chairman of the Board of Directors

Ryan M. Lance and Chief Executive Officer

(Principal executive officer)

/s/ Jeff W. Sheets Executive Vice President, Finance

Jeff W. Sheets and Chief Financial Officer

(Principal financial officer)

/s/ Glenda M. Schwarz Vice President and Controller

Glenda M. Schwarz (Principal accounting officer)

181
Table of Contents

/s/ Richard L. Armitage Director

Richard L. Armitage 

/s/ Richard H. Auchinleck Director

Richard H. Auchinleck 

/s/ James E. Copeland, Jr. Director

James E. Copeland, Jr. 

/s/ Jody L. Freeman Director

Jody L. Freeman 

/s/ Mohd H. Marican Director

Mohd H. Marican 

/s/ Robert A. Niblock Director

Robert A. Niblock 

/s/ Harald J. Norvik Director

Harald J. Norvik 

/s/ William K. Reilly Director

William K. Reilly 

/s/ William E. Wade, Jr. Director

William E. Wade, Jr. 

182
Exhibit 10.26.5

TARGETED VARIABLE LONG TERM INCENTIVE PROGRAM

SEPTEMBER 18, 2012

KEY EMPLOYEE AWARD

TERMS AND CONDITIONS

This Key Employee Award Terms and Conditions describes terms and conditions of Restricted Stock Unit Awards, as part of the

ConocoPhillips Targeted Variable Long Term Incentive Program (Program), granted under the 2011 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips (referred to as the Plan) by ConocoPhillips (Company) to certain eligible Employees (Employees).

These Terms and Conditions, together with the Annual Award Summary given to each Employee receiving an Award, form the Award

Agreement (the Agreement) relating to the Awards described. The Agreement covers Restricted Stock Units granted under the

Program, and the term Employee covers recipients of Awards under the Program.

1. Type and Size of Grant. Subject to the Plan and this Agreement, the Company grants to certain eligible Employees Restricted

Stock Units. Individual awards will be as set forth in the Annual Award Summary given to each Employee to whom an Award is

granted. The Annual Award Summary for each Employee is made a part of this Agreement with regard to such Employee.

2. Grant Date, Price, and Plan. The Grant Date and the Grant Price are set forth on the Award Summary given to each Employee to

whom an Award is granted. Awards are made under the 2011 Omnibus Stock and Performance Incentive Plan.

3. Restrictions, Forfeiture, and Lapse of Restrictions. The Restricted Stock Units subject hereto may be canceled or forfeited as

set forth herein. Except as otherwise noted in this Agreement, the following summary table describes restrictions and terms,

forfeiture, and lapse of restrictions, subject to the more detailed provisions set forth below:

Summary Table

Summary of Termination Rules

Status

 

Termination

Date 

Forfeiture or Lapsing of Restrictions

Retirement (age 65 and 5

years of service)

 

Prior to 6

months from

Grant Date 

Canceled upon Termination

 

6 months from

Grant Date &

after 

Restrictions lapse on Termination date

Layoff 

Prior to 6

months from

Grant Date 

Canceled upon Termination

 

6 months from

Grant Date &

after 

Award is prorated and restrictions on

remaining units lapse on Termination date

Disability

 

Prior to 1 month

from Grant Date 

Canceled upon Termination

 

1 month from

Grant Date &

after 

Award is prorated and restrictions on

remaining units lapse on Termination date

Effective 9/18/2012 Page 1 of 13 
Death

 

Prior to 1 month

from Grant Date 

Canceled upon Termination

 

1 month from

Grant Date &

after 

Award is prorated and restrictions on

remaining units lapse on Termination date

Divestitures, outsourcing, and moves to joint ventures

 

Any date after

Grant Date 

Canceled upon Termination, unless approval

otherwise

All other Terminations Canceled upon Termination

(a) Restrictions and Terms.

(i) The Award shall be held in escrow by the Company until the lapsing of restrictions placed upon the Award. The Employee

shall not have the right to sell, transfer, assign, or otherwise dispose of Restricted Stock Units granted in an Award until the

escrow is terminated. Except as set forth below, the Award shall be forfeited and the related Restricted Stock Units

canceled upon the Employee’s Termination of Employment with the Company prior to the lapsing of restrictions.

Restrictions shall lapse on one-third of the Restricted Stock Units granted in an Award (rounded down to the nearest whole

share) on the first anniversary of the Grant Date; restrictions shall lapse on a further one-third of the Restricted Stock

Units granted in an Award (rounded down to the nearest whole share) on the second anniversary of the Grant Date; and

restrictions shall lapse on the remaining Restricted Stock Units granted in an Award on the third anniversary of the Grant

Date. Upon the lapsing of restrictions, the number of shares of unrestricted Stock equal to the number of shares of

Restricted Stock Units for which the restrictions have so lapsed shall be registered in the Employee’s name, and the

related shares of Restricted Stock Units shall be canceled; provided, however, that in places where it is determined by the

Administrator that payout in the form of unrestricted Stock is prohibited by law, regulation, or decree, or where the cost of

legal compliance to issue the unrestricted Stock would be unreasonably expensive, the Fair Market Value of such

unrestricted Stock shall be paid in cash instead of settlement of the Award in unrestricted Stock. Cash payouts are only

permitted where such legal restrictions exist. Settlement of the Award in unrestricted Stock or cash payout, if any, shall be

made upon the lapsing of restrictions on the Award, but, in any event, shall be made no later than March 15 of the year

following the year in which such restrictions lapse.

(ii) Restricted Stock Units do not have any voting rights or other rights generally associated with Stock, and are merely an

obligation of the Company to make settlement in accordance with the terms and conditions applicable to such Restricted

Stock Units. Restricted Stock Units granted to Employees under the Program shall not accrue or be paid a dividend

equivalent.

(b) Termination of Employment.

(i) General Rule for Termination. If, prior to the date on which restrictions lapse in accordance with the schedule set forth in

the Award, the Employee’s employment with a Participating Company shall be terminated for any reason except death,

Disability, Retirement, or Layoff, any Restricted Stock Units remaining in escrow pursuant to such Award shall be

canceled and all rights thereunder shall cease; provided, however, that the Authorized Party may, in its or his sole

discretion, determine that all or any portion of an Award shall not be canceled due to Termination of Employment.

Effective 9/18/2012 Page 2 of 13 
(ii) Layoff or Retirement Within Six Months. If, prior to a date six months from the date an Award is granted, the Employee’s

employment with a Participating Company shall be terminated by reason of Layoff or Retirement, such Award shall be

canceled and all rights thereunder shall cease.

(iii) Layoff After Six Months. If, on or after a date six months from the date an Award is granted, the Employee’s employment

with a Participating Company shall be terminated by reason of Layoff, the Employee shall retain a prorated number of the

Restricted Stock Units of the Award. The number of Restricted Stock Units retained will be computed by multiplying the

original number of Restricted Stock Units granted by a fraction, the numerator of which is the number of full months of

employment from the first day of the month in which the Award was granted until the date the employee is terminated and

the denominator of which is 36. Such calculation shall be rounded down to the nearest whole share. From this result the

number of shares previously settled (or applied to tax withholding) from the Award shall be subtracted to determine the

prorated Award. In such case, the restrictions on the prorated Award shall lapse on the date of Termination of the Employee

from the employ of the Company and its subsidiaries, and settlement shall be made in accordance with the settlement

provisions above. The remainder of the Award shall be canceled and all rights thereunder shall cease.

(iv) Retirement After Six Months. If, on or after a date six months from the Grant Date of an Award, the Employee’s

employment with a Participating Company shall be terminated by reason of Retirement, the Employee shall retain all

rights provided by the Award at the time of such Termination of Employment. In such case, the restrictions on the Award

shall lapse on the date of Termination of the Employee from the employ of the Company and its subsidiaries, and

settlement shall be made in accordance with the settlement provisions above.

(v) Disability. If, after a date from the date an Award is granted, an Employee shall terminate employment following Disability

of the Employee, the Employee shall retain a prorated number of the Award shares or units granted. The number of Award

shares or units retained will be computed by multiplying the original number of Award shares or units granted by a fraction,

the numerator of which is the number of full months of employment from the first day of the month in which the Award

was granted until the date the employee is terminated and the denominator of which is 36. Such calculation shall be

rounded down to the nearest whole share. From this result the number of shares previously settled (or applied to tax

withholding) from the Award shall be subtracted to determine the prorated Award. In such case, the restrictions on the

prorated Award shall lapse on the date of Termination of the Employee from the employ of the Company and its

subsidiaries, and settlement shall be made in accordance with the settlement provisions above. The remainder of the Award

shall be canceled and all rights thereunder shall cease.

(vi) Death. If, after a date from the date an Award is granted, an Employee shall die while in the employ of a Participating

Company, the executor or administrator of the estate of the Employee or the person or persons to whom the Award shall

have been validly transferred by the executor or the administrator pursuant to will or the laws of descent and distribution

shall have the right to settlement of the Award to the same extent the Employee would have, had the Employee not died.

In such case, the restrictions on a prorated number of the Restricted Stock Units granted in the Award shall lapse upon the

determination of death by the Administrator, and settlement shall be made in accordance with the settlement provisions

above. The number of Award shares or units retained will be computed by multiplying the original number of Award shares

or units granted by a fraction, the numerator of which is the number of full months of employment from the first day of

the month in which the Award was granted until the date the employee is

Effective 9/18/2012 Page 3 of 13 
terminated and the denominator of which is 36. Such calculation shall be rounded down to the nearest whole share. From

this result the number of shares previously settled (or applied to tax withholding) from the Award shall be subtracted to

determine the prorated Award. In such case, the restrictions on the prorated Award shall lapse on the date of Termination of

the Employee from the employ of the Company and its subsidiaries, and settlement shall be made in accordance with the

settlement provisions above. The remainder of the Award shall be canceled and all rights thereunder shall cease. No

transfer of an Award, or of the unrestricted Stock or other proceeds of an Award, by the Employee by will or by the laws

of descent and distribution shall be effective to bind the Company unless the Administrator shall have been furnished with

written notice thereof and a copy of the will and such other evidence as the Administrator may deem necessary to establish

the validity of the transfer and the acceptance by the transferee or transferees of the terms and conditions of such Award.

(vii) Transfers and Leaves. Transfer of employment between Participating Companies shall not constitute Termination of

Employment for the purpose of any Award granted under the Program. Whether any leave of absence shall constitute

Termination of Employment for the purposes of any Award granted under the Program shall be determined by the

Administrator, in each case in accordance with applicable law and by application of the policies and procedures adopted by

the Company in relation to such leave of absence.

(viii) Divestiture, Outsourcing, or Move to Joint Venture. If, after the date the Award is granted, a Employee ceases to be

employed by Participating Company as a result of (a) the outsourcing of a function, (b) the sale or transfer of all or a portion

of the equity interest of such Participating Company (removing it from the controlled group of companies of which the

Company is a part), (c) the sale of all or substantially all of the assets of such Participating Company to another employer

outside of the controlled group of corporations (whether the Employee is offered employment or accepts employment

with the other employer), (d) the Termination of the Employee by a Participating Company followed by employment

within a reasonable time with a company or other entity in which the Company owns, directly or indirectly, at least a 50%

interest, prior to exercise of an Award, or (e) any other sale of assets determined by the Authorized Party to be considered a

divestiture under this program, the Authorized Party may, in its or his sole discretion, determine that all or a portion of any

such Award shall not be canceled. In such cases, the restrictions on the Award shall lapse on the date of Termination of the

Employee from the employ of the Company and its subsidiaries, and settlement shall be made in accordance with the

settlement provisions above.

(ix) Change of Control. In the event of a Change of Control, as defined hereafter, unless explicitly provided otherwise in the

applicable Award Agreement, all restrictions and other limitations applicable to any Restricted Stock Units granted in any

Award shall remain in effect and will lapse in accordance with other provisions of this Award Agreement. Settlement in

unrestricted Stock or cash shall be made at the same times and upon the same events as it would otherwise have been made

in accordance with the settlement provisions above.

(x) Notwithstanding anything herein to the contrary, in the event that this Award or any rights associated with this Award are

includible in income pursuant to section 409A of the Internal Revenue Code, settlement of the Award or any other

distribution hereunder due to Separation from Service with the Company and its subsidiaries shall not be made to a

“specified employee” (as that term is defined in section 409A(a)(2)(B)(i)) prior to six months after the specified employee’s

Separation from Service from the Company and its subsidiaries (or, if earlier, the date of death of the specified employee).

(c) Detrimental Activities and Suspension of Award.

Effective 9/18/2012 Page 4 of 13 
(i) If the Authorized Party determines that, subsequent to the grant of any Award, the Employee has engaged or is engaging in

any activity which, in the sole judgment of the Authorized Party, is or may be detrimental to the Company or a subsidiary,

the Authorized Party may cancel all or part of the Restricted Stock Units held in escrow pursuant to the Award or Awards

granted to that Employee.

(ii) If the Authorized Party, in its or his sole discretion, determines that the lapsing of restrictions on Restricted Stock Units

held in escrow pursuant to any Award has the possibility of violating any law, regulation, or decree pertaining to the

Company or Employee, the Authorized Party may freeze or suspend the Employee’s right to settlement or payout of the

Award until such time as the lapse of restrictions would no longer, in the sole discretion of the Authorized Party, have the

possibility of violating such law, regulation, or decree.

(iii) Notwithstanding anything herein to the contrary, any Award is subject to forfeiture or recoupment, in whole or in part,

under applicable law, including the Sarbanes-Oxley Act and the Dodd-Frank Act.

4. Assignment of Award Upon Death. Rights under the Plans and this Agreement cannot be assigned or transferred other than by

(i) will or (ii) the laws of descent and distribution.

5. Tax Withholding. In all cases the Employee will be responsible to pay all required withholding taxes associated with an Award.

Should a withholding tax obligation arise with regard to an Award or the lapsing of restrictions on Restricted Stock Units granted in

an Award, the withholding tax may be satisfied by withholding units or shares of Stock. The value of the units or shares of Stock

withheld for this purpose shall not exceed the minimum withholding amount required by applicable laws and regulations. In cases

where a withholding tax obligation arises prior to the lapse of restrictions on Restricted Stock Units granted in an Award, the

withholding tax may be satisfied instead by other methods determined by the Administrator, such as payment of cash by the

Employee or, if agreed by the Employee, payroll withholding. In cases where payment by payroll withholding cannot be made

due to circumstances arising after the election or where the Administrator has determined that such withholding would violate

any applicable law, regulation, or decree, shares of Stock shall be withheld instead. When necessary, lapsing of restrictions may

be accelerated by the Authorized Party to the extent necessary to provide shares of Stock to satisfy any withholding tax obligation.

This withholding tax obligation includes, but is not limited to, federal, state, and local taxes, including applicable non-U.S. taxes

such as U.K. PAYE.

6. Shareholder Rights for Restricted Stock Units. The Employee shall not have the rights of a shareholder until the Restricted

Stock Unit has been canceled and ownership of shares of Stock has been transferred to the Employee.

7. Certain Adjustments. In the event certain corporate transactions, recapitalizations, or stock splits occur while Restricted Stock

Units are outstanding, the Grant Price and the number of Restricted Stock Units shall be correspondingly adjusted.

8. Relationship to the Plan. In addition to the terms and conditions described in this Agreement, Awards are subject to all other

applicable provisions of the Plan. The decisions of the Committee with respect to questions arising as to the interpretation of the

Plan or this Agreement and as to findings of fact, shall be final, conclusive, and binding.

9. No Employment Guarantee. No provision of this Agreement shall confer any right upon the Employee to continued

employment with any Participating Company.

Effective 9/18/2012 Page 5 of 13 
10. Governing Law. This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of

Delaware.

11. Amendment. Without the consent of the Employee, this Agreement may be amended or supplemented (i) to cure any ambiguity

or to correct or supplement any provision herein which may be defective or inconsistent with any other provision herein, or (ii) to

add to the covenants and agreements of the Company for the benefit of an Employee or to add to the rights of an Employee or to

surrender any right or power reserved to or conferred upon the Company in this Agreement, provided, in each case, that such

changes or corrections shall not adversely affect the rights of the Employee with respect to the grant of an Award evidenced

hereby without the Employee’s consent, or (iii) to make such other changes as the Company, upon advice of counsel, determines

are necessary or advisable because of the adoption or promulgation of, or change in or of the interpretation of, any law or

governmental rule or regulation, including any applicable federal or state securities or tax laws.

Effective 9/18/2012 Page 6 of 13 
DEFINITIONS

Capitalized terms not defined below shall have the meanings set forth in the Plan.

Authorized Party means the person who is authorized to approve an Award, exercise discretion or take action under the Administrative

Procedure for the Restricted Stock Program and pursuant to the Program. With regard to Senior Officers, the Committee is the

Authorized Party. With regard to other Employees, the Chief Executive Officer, acting as the Special Equity Award Committee of the

Board of Directors of the Company, is the Authorized Party, although the Committee may act concurrently as the Authorized Party.

Award means any Restricted Stock Units granted to an Employee pursuant to such applicable terms, conditions, and limitations as the

Authorized Party may establish in order to fulfill the objectives of the Program.

Change of Control has the meaning set forth in Attachment A to these Terms and Conditions.

Committee means the Human Resources and Compensation Committee of the Board of Directors of the Company, or any successor

committee to it.

Company means ConocoPhillips, a Delaware corporation.

Disability means a disability for which the employee in question has been determined to be entitled to either (i) benefits under the

applicable plan of long-term disability of the Company or its subsidiaries or (ii) disability benefits under the Social Security Act. In the

absence of any such determination, the Authorized Party may make a determination that the employee has a Disability.

Fair Market Value means, as of a particular date, the mean between the highest and lowest sales price per share of such Stock on the

consolidated transaction reporting system for the principal national securities exchange on which shares of Stock are listed on that date,

or, if there shall have been no such sale so reported on that date, on the next preceding date on which such a sale was so reported, or, at

the discretion of the Committee, the price prevailing on the exchange at a designated time.

Grant Price means the Fair Market Value for one share of Stock as of the date of the grant of an Award. Grant price is not adjusted for

any restrictions applicable to the Award.

Layoff means an applicable Termination of Employment due to layoff under the ConocoPhillips Severance Pay Plan, the

ConocoPhillips Executive Severance Plan, or the ConocoPhillips Key Employee Change in Control Severance Plan, or layoff or

redundancy under any similar layoff or redundancy plan which the Company or its subsidiaries may adopt from time to time. If all or any

portion of the benefits under the redundancy or layoff plan are contingent on the employee’s signing a general release of liability, such

Termination shall not be considered as a “Layoff” for purposes of this Award unless the employee executes and does not revoke a

general release of liability, acceptable to the Company, under the terms of such layoff or redundancy plan. In order to be considered a

layoff for purposes of this Award, the Termination of Employment must also be considered a Separation from Service.

Participating Company includes ConocoPhillips and its 100% owned subsidiaries, including both those directly owned and those owned

through subsidiaries, whose participation has been approved by the Authorized Party.

Restricted Stock Unit means a unit equal to one share of Stock (as determined by the Authorized Party) that is subject to forfeiture

provisions or that has certain restrictions attached to the ownership thereof.

Effective 9/18/2012 Page 7 of 13 
Retirement means Termination at age 65 or older with a minimum of 5 years service with a Participating Company; provided, however,

that with regard to an Employee not on the United States payroll, the CEO may approve the use of a different definition. Service is

defined by the policies of the Participating Company.

Senior Officer means the Chairman of the Board, the CEO, all other executive officers of the Company (determined in accordance

with the Company’s custom and practice pursuant to section 16(b) of the Securities Exchange Act of 1934, as amended), all other

employees of the Company who report directly to the CEO and whose salary grade is 23 or higher, and all other employees of the

Company whose salary grade is 26 or higher.

Separation from Service means “separation from service” as that term is used in section 409A of the Internal Revenue Code.

Stock means shares of common stock of the Company, par value $.01. Stock may also be referred to as “Common Stock.”

Termination and Termination of Employment mean cessation of employment with the Participating Companies, determined in

accordance with the policies and practices of the Participating Company for whom the Employee was last performing services.

Effective 9/18/2012 Page 8 of 13 
Attachment A

Change of Control

The following definitions apply to the Change of Control provision in Paragraph 10 of the Plan.

Affiliate shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the

Exchange Act, as in effect at the time of determination.

Associate shall mean, with reference to any Person, (a) any corporation, firm, partnership, association, unincorporated

organization or other entity (other than the Company or a subsidiary of the Company) of which such Person is an officer or general

partner (or officer or general partner of a general partner) or is, directly or indirectly, the Beneficial Owner of 10% or more of any class

of equity securities, (b) any trust or other estate in which such Person has a substantial beneficial interest or as to which such Person

serves as trustee or in a similar fiduciary capacity and (c) any relative or spouse of such Person, or any relative of such spouse, who has

the same home as such Person.

Beneficial Owner shall mean, with reference to any securities, any Person if:

(a) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, is the “Beneficial Owner” of (as

determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act, as in effect at the time of

determination) such securities or otherwise has the right to vote or dispose of such securities;

(b) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, has the right or obligation to acquire

such securities (whether such right or obligation is exercisable or effective immediately or only after the passage of time or the

occurrence of an event) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the

exercise of conversion rights, exchange rights, other rights, warrants or options, or otherwise; provided, however, that a Person

shall not be deemed the Beneficial Owner of, or to “beneficially own,” (i) securities tendered pursuant to a tender or exchange

offer made by such Person or any of such Person’s Affiliates or Associates until such tendered securities are accepted for

purchase or exchange or (ii) securities issuable upon exercise of Exempt Rights; or

(c) such Person or any of such Person’s Affiliates or Associates (i) has any agreement, arrangement or understanding

(whether or not in writing) with any other Person (or any Affiliate or Associate thereof) that beneficially owns such securities for

the purpose of acquiring, holding, voting (except as set forth in the proviso to subsection (a) of this definition) or disposing of such

securities or (ii) is a member of a group (as that term is used in Rule 13d-5(b) of the General Rules and Regulations under the

Exchange Act) that includes any other Person that beneficially owns such securities;

provided, however, that nothing in this definition shall cause a Person engaged in business as an underwriter of securities to be the

Beneficial Owner of, or to beneficially own, any securities acquired through such Person’s participation in good faith in a firm

commitment underwriting until the expiration of 40 days after the date of such acquisition. For purposes hereof, “voting” a security shall

include voting, granting a proxy, consenting or making a request or demand relating to corporate action (including, without limitation, a

demand for a shareholder list, to call a shareholder meeting or to inspect corporate books and records) or otherwise giving an

authorization (within the meaning of Section 14(a) of the Exchange Act) in respect of such security.

The terms beneficially own and beneficially owning shall have meanings that are correlative to this definition of the

term Beneficial Owner.

Effective 9/18/2012 Page 9 of 13 
Board shall have the meaning set forth in the foregoing Plan.

Change of Control shall mean any of the following occurring on or after May 11, 2011:

(a) any Person (other than an Exempt Person) shall become the Beneficial Owner of 20% or more of the shares of

Common Stock then outstanding or 20% or more of the combined voting power of the Voting Stock of the Company then

outstanding; provided, however, that no Change of Control shall be deemed to occur for purposes of this subsection (a) if such

Person shall become a Beneficial Owner of 20% or more of the shares of Common Stock or 20% or more of the combined voting

power of the Voting Stock of the Company solely as a result of (i) an Exempt Transaction or (ii) an acquisition by a Person

pursuant to a reorganization, merger or consolidation, if, following such reorganization, merger or consolidation, the conditions

described in clauses (i), (ii) and (iii) of subsection (c) of this definition are satisfied;

(b) individuals who, as of May 11, 2011, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at

least a majority of the Board; provided, however, that any individual becoming a director subsequent to May 11, 2011 whose

election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors

then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board;

provided, further, that there shall be excluded, for this purpose, any such individual whose initial assumption of office occurs as a

result of any actual or threatened Election Contest that is subject to the provisions of Rule 14a-11 of the General Rules and

Regulations under the Exchange Act;

(c) the Company shall consummate a reorganization, merger, or consolidation, in each case, unless, following such

reorganization, merger, or consolidation, (i) 50% or more of the then outstanding shares of common stock of the corporation, or

common equity securities of an entity other than a corporation, resulting from such reorganization, merger, or consolidation and

the combined voting power of the then outstanding Voting Stock of such corporation or other entity are beneficially owned,

directly or indirectly, by all or substantially all of the Persons who were the Beneficial Owners of the outstanding Common

Stock immediately prior to such reorganization, merger, or consolidation in substantially the same proportions as their ownership,

immediately prior to such reorganization, merger, or consolidation, of the outstanding Common Stock, (ii) no Person (excluding

any Exempt Person or any Person beneficially owning, immediately prior to such reorganization, merger, or consolidation,

directly or indirectly, 20% or more of the Common Stock then outstanding or 20% or more of the combined voting power of the

Voting Stock of the Company then outstanding) beneficially owns, directly or indirectly, 20% or more of the then outstanding

shares of common stock of the corporation, or common equity securities of an entity other than a corporation, resulting from

such reorganization, merger, or consolidation or the combined voting power of the then outstanding Voting Stock of such

corporation or other entity, and (iii) at least a majority of the members of the board of directors of the corporation, or the body

which is most analogous to the board of directors of a corporation if not a corporation, resulting from such reorganization, merger,

or consolidation were members of the Incumbent Board at the time of the initial agreement or initial action by the Board providing

for such reorganization, merger, or consolidation; or

(d) (i) the shareholders of the Company shall approve a complete liquidation or dissolution of the Company unless such

liquidation or dissolution is approved as part of a plan of liquidation and dissolution involving a sale or disposition of all or

substantially all of the assets of the Company to a corporation with respect to which, following such sale or other disposition, all of

the requirements of clauses (ii)(A), (B), and (C) of this subsection (d) are satisfied, or (ii) the Company shall consummate the sale

or other disposition of all or substantially all of the assets of the Company, other than to a corporation or other entity, with respect

to which, following such sale or other disposition,

Effective 9/18/2012 Page 10 of 13 
(A) 50% or more of the then outstanding shares of common stock of such corporation, or common equity securities of an entity

other than a corporation, and the combined voting power of the Voting Stock of such corporation or other entity is then

beneficially owned, directly or indirectly, by all or substantially all of the Persons who were the Beneficial Owners of the

outstanding Common Stock immediately prior to such sale or other disposition in substantially the same proportion as their

ownership, immediately prior to such sale or other disposition, of the outstanding Common Stock, (B) no Person (excluding any

Exempt Person and any Person beneficially owning, immediately prior to such sale or other disposition, directly or indirectly, 20%

or more of the Common Stock then outstanding or 20% or more of the combined voting power of the Voting Stock of the

Company then outstanding) beneficially owns, directly or indirectly, 20% or more of the then outstanding shares of common

stock of such corporation, or common equity securities of an entity other than a corporation, and the combined voting power of

the then outstanding Voting Stock of such corporation or other entity, and (C) at least a majority of the members of the board of

directors of such corporation, or the body which is most analogous to the board of directors of a corporation if not a corporation,

were members of the Incumbent Board at the time of the initial agreement or initial action of the Board providing for such sale or

other disposition of assets of the Company.

Common Stock shall have the meaning set forth in the foregoing Plan.

Company shall have the meaning set forth in the foregoing Plan.

Election Contest shall mean a solicitation of proxies of the kind described in Rule 14a-12(c) under the Exchange Act.

Exchange Act shall mean the Securities Exchange Act of 1934, as amended.

Exempt Person shall mean any of the Company, any subsidiary of the Company, any employee benefit plan of the

Company or any subsidiary of the Company, and any Person organized, appointed or established by the Company for or pursuant to the

terms of any such plan.

Exempt Rights shall mean any rights to purchase shares of Common Stock or other Voting Stock of the Company if at the

time of the issuance thereof such rights are not separable from such Common Stock or other Voting Stock ( i.e., are not transferable

otherwise than in connection with a transfer of the underlying Common Stock or other Voting Stock), except upon the occurrence of a

contingency, whether such rights exist as of May 11, 2011 or are thereafter issued by the Company as a dividend on shares of Common

Stock or other Voting Securities or otherwise.

Exempt Transaction shall mean an increase in the percentage of the outstanding shares of Common Stock or the

percentage of the combined voting power of the outstanding Voting Stock of the Company beneficially owned by any Person solely as a

result of a reduction in the number of shares of Common Stock then outstanding due to the repurchase of Common Stock or Voting

Stock by the Company, unless and until such time as (a) such Person or any Affiliate or Associate of such Person shall purchase or

otherwise become the Beneficial Owner of additional shares of Common Stock constituting 1% or more of the then outstanding shares

of Common Stock or additional Voting Stock representing 1% or more of the combined voting power of the then outstanding Voting

Stock, or (b) any other Person (or Persons) who is (or collectively are) the Beneficial Owner of shares of Common Stock constituting

1% or more of the then outstanding shares of Common Stock or Voting Stock representing 1% or more of the combined voting power of

the then outstanding Voting Stock shall become an Affiliate or Associate of such Person.

Person shall mean any individual, firm, corporation, partnership, association, trust, unincorporated organization or other

entity.

Effective 9/18/2012 Page 11 of 13 
Voting Stock shall mean, (1) with respect to a corporation, all securities of such corporation of any class or series that are

entitled to vote generally in the election of, or to appoint by contract, directors of such corporation (excluding any class or series that

would be entitled so to vote by reason of the occurrence of any contingency, so long as such contingency has not occurred) and (ii) with

respect to an entity which is not a corporation, all securities of any class or series that are entitled to vote generally in the election of, or

to appoint by contract, members of the body which is most analogous to the board of directors of a corporation.

Effective 9/18/2012 Page 12 of 13 
Attachment B

2012 Restricted Stock Unit Early Vesting Schedule for

Retirement, Layoff, Disability & Death

Termination Date

 

TVLTI Grant Payout %

 Retirement Layoff 

 Disability and 

Death

Less than 1 month 0% 0% 0%

Oct 18 2012 - Nov 17 2012 0% 0% 3%

Nov 18 2012 - Dec 17 2012 0% 0% 6%

Dec 18 2012 - Jan 17 2013 0% 0% 8%

Jan 18 2013 - Feb 17 2013 0% 0% 11%

Feb 18 2013 - Mar 17 2013 0% 0% 14%

Mar 18 - Mar 31 2013 100% 17% 17%

Apr-2013 100% 19% 19%

May-2013 100% 22% 22%

Jun-2013 100% 25% 25%

Jul-2013 100% 28% 28%

Aug-2013 100% 31% 31%

Sep-2013 100% 33% 33%

Oct-2013 100% 36% 36%

Nov-2013 100% 39% 39%

Dec-2013 100% 42% 42%

Jan-2014 100% 44% 44%

Feb-2014 100% 47% 47%

Mar-2014 100% 50% 50%

Apr-2014 100% 53% 53%

May-2014 100% 56% 56%

Jun-2014 100% 58% 58%

Jul-2014 100% 61% 61%

Aug-2014 100% 64% 64%

Sep-2014 100% 67% 67%

Oct-2014 100% 69% 69%

Nov-2014 100% 72% 72%

Dec-2014 100% 75% 75%

Jan-2015 100% 78% 78%

Feb-2015 100% 81% 81%

Mar-2015 100% 83% 83%

Apr-2015 100% 86% 86%

May-2015 100% 89% 89%

Jun-2015 100% 92% 92%

Jul-2015 100% 94% 94%

Aug-2015 100% 97% 97%

Sep-2015 100% 100% 100%

* For purposes of this table, Termination Date is the first day a participant is no longer employed by and performing services for ConocoPhillips or its

subsidiaries.

Effective 9/18/2012 Page 13 of 13 
Exhibit 10.26.6

PERFORMANCE SHARE PROGRAM

FEBRUARY 5, 2013

FINAL PAYOUT FOR PERFORMANCE PERIOD VIII (PSP VIII TAIL)

PERFORMANCE SHARE UNIT

AWARD TERMS AND CONDITIONS

These Performance Share Unit Award Terms and Conditions describe terms and conditions of Performance Share Unit Awards, as part

of the ConocoPhillips Performance Share Program (Program), granted under the 2011 Omnibus Stock and Performance Incentive Plan

of ConocoPhillips (referred to as the Plan) by ConocoPhillips (Company) to you as an eligible employee (Grantee). These Terms and

Conditions, together with the Annual Award Summary given to each Grantee receiving an Award, form the Award Agreement (the

Agreement) relating to the Awards described. Subject to the Plan and this Agreement, the Company grants to the Grantee Performance

Share Units. Individual awards will be as set forth in the Annual Award Summary given to each Grantee to whom an Award is granted.

The Annual Award Summary for each Grantee is made a part of this Agreement with regard to such Grantee.

AWARD: Performance Stock Unit (PSU) Award granted by the Authorized Party under the provisions of the Plan. The PSUs will be

noted in a book entry account created for the Grantee.

PSU: A unit evidencing the right to receive one share of ConocoPhillips Stock, $0.01 par value, under the circumstances described

in these Terms and Conditions.

VOTING RIGHTS: The named owner of the PSUs has no voting rights for the units, but is considered the beneficial owner for all

purposes including ownership and control reports such as the annual proxy statement.

DIVIDEND EQUIVALENTS: Dividend equivalent payment, equal to the regular dividend payment as declared by the Board of

Directors on an equivalent number of common stock from time to time, will be made to the named owner of the units.

Under current tax law, these payments are taxable as compensation (i.e., ordinary income) in the year distributed.

RETIREMENT PLAN EARNINGS: The issuance of these PSUs does not constitute earnings under any retirement plan sponsored by

a ConocoPhillips company. The value of the units at the time the restrictions lapse also does not constitute earnings under

any retirement plan sponsored by a ConocoPhillips company. Neither the issuance of nor lapsing of restrictions on PSUs will

have any impact on any retirement plans or any other compensation plan sponsored by a ConocoPhillips company.

TAX INFORMATION: This matter is more thoroughly covered in the document entitled “Tax Aspects of Performance Share Units,”

however, in general terms the value of these units is not considered taxable income until the restrictions lapse.

Effective 2/5/2013

 - 1 - 
BENEFICIARY: In the event of the death of the named owner of these units prior to the lapsing of restrictions for other reasons, such restrictions

will lapse and shares of unrestricted common stock equal in number to the PSUs will be issued to the beneficiary designated by the

named owner of the units.

CHANGE OF CONTROL: If a Change of Control occurs, the PSUs shall vest and may not be forfeited but the restrictions on these shares will

lapse and unrestricted shares will be delivered to the Grantee upon Termination of Employment.

RESTRICTIONS: The following restrictions relate to the PSUs:

The PSUs will be held in escrow for the Grantee. As provided herein, the Grantee will have all rights of economic

ownership to such unit including the right to receive dividend equivalents, except that the Grantee shall not have the right

to sell, transfer, assign, or otherwise dispose of such units until the escrow is terminated (such restrictions being known as

the “Transfer Restrictions”).

Unless postponed pursuant to an effective election, as described in the sections on Initial Election and Subsequent Election

below, the escrow shall end on the earliest of any of the following occurrences, with Transfer Restrictions to lapse and

settlement be made as set forth in the section on Settlement below:

 1. The Termination of the Grantee’s employment as a result of Layoff of the Grantee;

 2. The Termination of the Grantee’s employment after attainment of age 55 and completion of 5 years of service

with the Company or its subsidiaries;

 3. The Termination of the Grantee’s employment due to Death;

 4. The Termination of the Grantee’s employment following Disability of the Grantee;

 5. The Termination of the Grantee’s employment following a Change of Control; or

 6. February 5, 2018.

In the absence of an effective election, as described in the sections on Initial Election and Subsequent Election below, the

Transfer Restrictions shall lapse and the PSUs (including any such that are awarded after the Separation from Service of

the Grantee) shall be settled in cash on the date that is the later of (a) the end of the escrow period and (b) the earliest of the

Grantee’s death, February 5, 2018, or six months after the date of the Grantee’s Separation from Service for a reason

other than death.

INITIAL ELECTION: A Grantee may elect on an election form delivered to the Plan Administrator at a time set by the Plan Administrator (which

shall be on or before December 31, 2009) to have the escrow for the PSUs continue and the Transfer Restrictions applicable to these

PSUs continue and settlement in cash postponed and made in either:

1. one lump sum payment settled six months after Separation from Service with the Company and its subsidiaries,

or

Effective 2/5/2013

 - 2 - 
 2. in a series of annual installments, using a declining balance method, over a period of three, five, ten, or fifteen

years after Separation from Service with the Company and its subsidiaries.

In the absence of such an election, the escrow will end and settlement shall be made in one lump sum payment in cash on

February 5, 2018.

SUBSEQUENT ELECTION: A Grantee may make an election to change the time or form of payment elected under the Initial Election section

above or the payment to be made under the Restrictions section above, but only if the following rules are satisfied:

1. The election to change the time or form of payment may not take effect until at least twelve months after the date

on which such election is made;

2. Payment under such election may not be made earlier than at least five years from the date the payment would have

otherwise been made or commenced;

3. An election may provide for either a lump sum payment or installment payments;

4. An election to receive payments in installments shall be treated as a single payment for purposes of these rules;

5. Installment payments may be made only annually, over a period of from one to fifteen years as elected;

6. The election may not result in an impermissible acceleration of payment prohibited under section 409A of the

Internal Revenue Code;

7. No more than four such elections shall be permitted with respect to the PSUs subject to this Award; and

8. No payment may be made after the date that is twenty (20) years after the date of the Grantee’s Separation from

Service.

If an election under this section becomes effective, the escrow and the Transfer Restrictions applicable to the PSUs shall

continue until the time set in the election for the settlement of the PSUs in cash.

SETTLEMENT: Upon termination of the escrow the Company shall, at the time stated above, deliver to each Grantee an amount equal to the Fair

Market Value of the PSUs at the time of the termination of escrow, unless the lapsing of restrictions has been delayed pursuant to a

schedule permitted under this Award. In all cases the Grantee will be responsible to pay all required withholding taxes associated with the

Award. The Grantee must pay any required withholding taxes by having shares equal in value to the applicable withholding taxes

withheld by the Company unless the Company, in its sole discretion deems that another method is allowable. The value of the shares

withheld for this purpose shall not exceed the minimum withholding amount required by the applicable laws and regulations.

The Fair Market Value of the Award received by the Grantee shall be deemed equal to the average of the reported highest

and lowest selling prices per share of the Company’s Stock as reported on the composite tape of the New York Stock

Exchange (or such other reporting system as shall be selected by the Committee) on the date termination of escrow occurs

(or the last preceding date on which the Stock was traded, if no trades occurred on the applicable date).

Effective 2/5/2013

 - 3 - 
FORFEITURE: A Grantee’s right, title, and interest in Performance Share Units awarded under the PSP or derived from such Performance Share

Units, or the ownership thereof, shall be forfeited if the Grantee terminates employment prior to termination of the escrow period;

provided, however, any transfer between the Company and any Subsidiary, or between Subsidiaries at the request of the Company or

such Subsidiaries, shall not result in forfeiture.

DETRIMENTAL ACTIVITIES: If the Authorized Party determines that, subsequent to the grant of any Award, the Employee has engaged or is

engaging in any activity which, in the sole judgment of the Authorized Party, is or may be detrimental to the Company or a subsidiary, the

Authorized Party may cancel all or part of the Restricted Stock or Restricted Stock Units held in escrow pursuant to the Award or

Awards granted to that Employee.

If the Authorized Party, in its or his sole discretion, determines that the lapsing of restrictions on Restricted Stock or

Restricted Stock Units held in escrow pursuant to any Award has the possibility of violating any law, regulation, or decree

pertaining to the Company or Employee, the Authorized Party may freeze or suspend the Employee’s right to settlement or

payout of the Award until such time as the lapse of restrictions would no longer, in the sole discretion of the Authorized

Party, have the possibility of violating such law, regulation, or decree.

Notwithstanding anything herein to the contrary, this Award is subject to forfeiture or recoupment, in whole or in part,

under applicable law, including the Sarbanes-Oxley Act and the Dodd-Frank Act.

RECAPITALIZATION: Upon any change in the outstanding stock of the Company by reason of any stock dividend, stock split, reverse stock split,

recapitalization, reclassification, or other similar changes, the Committee shall make corresponding adjustments to the Total Target

Awards and Performance Share Awards.

Effective 2/5/2013

 - 4 - 
DEFINITIONS:

Capitalized terms not defined below shall have the meanings set forth in the Plan under which the Award is granted.

Authorized Party means the person who is authorized to approve an Award, exercise discretion, or take action under the Administrative

Procedure for the Performance Share Program and pursuant to the Program. With regard to Senior Officers, the Committee is the

Authorized Party. With regard to other Employees, the Chief Executive Officer, acting as the Special Equity Award Committee of the

Board of Directors of the Company, is the Authorized Party, although the Committee may act concurrently as the Authorized Party.

Award means any Performance Share Units granted to an Employee pursuant to such applicable terms, conditions, and limitations as the

Authorized Party may establish in order to fulfill the objectives of the Program.

Change of Control has the meaning set forth in Annex A to these Terms and Conditions.

Committee means the Human Resources and Compensation Committee of the Board of Directors of the Company, or any successor

committee to it.

Company means ConocoPhillips, a Delaware corporation.

Disability means a disability for which the employee in question has been determined to be entitled to either (i) benefits under the

applicable plan of long-term disability of the Company or its subsidiaries or (ii) disability benefits under the Social Security Act. In the

absence of any such determination, the Authorized Party may make a determination that the employee has a Disability.

Fair Market Value means, as of a particular date, the mean between the highest and lowest sales price per share of such Stock on the

consolidated transaction reporting system for the principal national securities exchange on which shares of Stock are listed on that date,

or, if there shall have been no such sale so reported on that date, on the next preceding date on which such a sale was so reported, or, at

the discretion of the Committee, the price prevailing on the exchange at a designated time.

Grant Price means the Fair Market Value for one share of Stock as of the date of the grant of an Award. Grant price is not adjusted for

any restrictions applicable to the Award.

Layoff means an applicable Termination of Employment due to layoff under the ConocoPhillips Severance Pay Plan, the ConocoPhillips

Executive Severance Plan, or the ConocoPhillips Key Employee Change in Control Severance Plan, or layoff or redundancy under any

similar layoff or redundancy plan which the Company or its subsidiaries may adopt from time to time. If all or any portion of the benefits

under the redundancy or layoff plan are contingent on the employee’s signing a general release of liability, such Termination shall not be

considered as a “Layoff” for purposes of this Award unless the employee executes and does not revoke a general release of liability,

acceptable to the Company, under the terms of such layoff or redundancy plan. In order to be considered a layoff for purposes of this

Award, the Termination of Employment must also be considered a Separation from Service.

Effective 2/5/2013

 - 5 - 
Participating Company includes ConocoPhillips and its 100% owned subsidiaries, including both those directly owned and those owned

through subsidiaries, whose participation has been approved by the Authorized Party.

Performance Share Unit or PSU means the type of restricted stock unit issued under the Performance Share Program (as determined

by the Authorized Party) that is subject to forfeiture provisions or that has certain restrictions attached to the ownership thereof.

Restricted Stock Unit means a unit equal to one share of Stock (as determined by the Authorized Party) that is subject to forfeiture

provisions or that has certain restrictions attached to the ownership thereof.

Retirement means Termination at age 55 or older with a minimum of 5 years service with a Participating Company; provided, however,

that with regard to an Employee not on the United States payroll, the CEO may approve the use of a different definition. Service is

defined by the policies of the Participating Company.

Senior Officer means the Chairman of the Board, the CEO, all other executive officers of the Company (determined in accordance

with the Company’s custom and practice pursuant to section 16(b) of the Securities Exchange Act of 1934, as amended), all other

employees of the Company who report directly to the CEO and whose salary grade is 23 or higher, and all other employees of the

Company whose salary grade is 26 or higher.

Stock means shares of common stock of the Company, par value $.01. Stock may also be referred to as “Common Stock.”

Termination, Termination of Employment, and Separation from Service each mean “separation from service” as that term is used in

section 409A of the Internal Revenue Code.

Effective 2/5/2013

 - 6 - 
Annex A

Change of Control

The following definitions apply to the Change of Control provision in Paragraph 10 of the Plan.

Affiliate shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the

Exchange Act, as in effect at the time of determination.

Associate shall mean, with reference to any Person, (a) any corporation, firm, partnership, association, unincorporated

organization or other entity (other than the Company or a subsidiary of the Company) of which such Person is an officer or general

partner (or officer or general partner of a general partner) or is, directly or indirectly, the Beneficial Owner of 10% or more of any class

of equity securities, (b) any trust or other estate in which such Person has a substantial beneficial interest or as to which such Person

serves as trustee or in a similar fiduciary capacity and (c) any relative or spouse of such Person, or any relative of such spouse, who has

the same home as such Person.

Beneficial Owner shall mean, with reference to any securities, any Person if:

(a) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, is the “beneficial owner” of

(as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act, as in effect at the

time of determination) such securities or otherwise has the right to vote or dispose of such securities;

(b) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, has the right or obligation to

acquire such securities (whether such right or obligation is exercisable or effective immediately or only after the passage of

time or the occurrence of an event) pursuant to any agreement, arrangement or understanding (whether or not in writing)

or upon the exercise of conversion rights, exchange rights, other rights, warrants or options, or otherwise; provided,

however, that a Person shall not be deemed the Beneficial Owner of, or to “beneficially own,” (i) securities tendered

pursuant to a tender or exchange offer made by such Person or any of such Person’s Affiliates or Associates until such

tendered securities are accepted for purchase or exchange or (ii) securities issuable upon exercise of Exempt Rights; or

(c) such Person or any of such Person’s Affiliates or Associates (i) has any agreement, arrangement or

understanding (whether or not in writing) with any other Person (or any Affiliate or Associate thereof) that beneficially

owns such securities for the purpose of acquiring, holding, voting (except as set forth in the proviso to subsection (a) of this

definition) or disposing of such securities or (ii) is a member of a group (as that term is used in Rule 13d-5(b) of the

General Rules and Regulations under the Exchange Act) that includes any other Person that beneficially owns such

securities;

provided, however, that nothing in this definition shall cause a Person engaged in business as an underwriter of securities to be the

Beneficial Owner of, or to beneficially own, any securities acquired through such Person’s participation in good faith in a firm

commitment underwriting until the expiration of 40 days after the date of such acquisition. For purposes hereof, “voting” a security shall

include voting, granting a proxy, consenting or making a request or demand relating to corporate action (including, without limitation, a

demand for a shareholder list, to call a shareholder meeting or to inspect

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corporate books and records) or otherwise giving an authorization (within the meaning of Section 14(a) of the Exchange Act) in respect

of such security.

The terms beneficially own and beneficially owning shall have meanings that are correlative to this definition of the term

Beneficial Owner.

Board shall have the meaning set forth in the foregoing Plan.

Change of Control shall mean any of the following occurring on or after May 11, 2011:

(a) any Person (other than an Exempt Person) shall become the Beneficial Owner of 20% or more of the shares of

Common Stock then outstanding or 20% or more of the combined voting power of the Voting Stock of the Company then

outstanding; provided, however, that no Change of Control shall be deemed to occur for purposes of this subsection (a) if

such Person shall become a Beneficial Owner of 20% or more of the shares of Common Stock or 20% or more of the

combined voting power of the Voting Stock of the Company solely as a result of (i) an Exempt Transaction or (ii) an

acquisition by a Person pursuant to a reorganization, merger or consolidation, if, following such reorganization, merger or

consolidation, the conditions described in clauses (i), (ii) and (iii) of subsection (c) of this definition are satisfied;

(b) individuals who, as of May 11, 2011, constitute the Board (the “Incumbent Board”) cease for any reason to

constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to

May 11, 2011 whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at

least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a

member of the Incumbent Board; provided, further, that there shall be excluded, for this purpose, any such individual

whose initial assumption of office occurs as a result of any actual or threatened Election Contest that is subject to the

provisions of Rule 14a-11 of the General Rules and Regulations under the Exchange Act;

(c) the Company shall consummate a reorganization, merger, or consolidation, in each case, unless, following such

reorganization, merger, or consolidation, (i) 50% or more of the then outstanding shares of common stock of the

corporation, or common equity securities of an entity other than a corporation, resulting from such reorganization, merger,

or consolidation and the combined voting power of the then outstanding Voting Stock of such corporation or other entity are

beneficially owned, directly or indirectly, by all or substantially all of the Persons who were the Beneficial Owners of the

outstanding Common Stock immediately prior to such reorganization, merger, or consolidation in substantially the same

proportions as their ownership, immediately prior to such reorganization, merger, or consolidation, of the outstanding

Common Stock, (ii) no Person (excluding any Exempt Person or any Person beneficially owning, immediately prior to

such reorganization, merger, or consolidation, directly or indirectly, 20% or more of the Common Stock then outstanding

or 20% or more of the combined voting power of the Voting Stock of the Company then outstanding) beneficially owns,

directly or indirectly, 20% or more of the then outstanding shares of common stock of the corporation, or common equity

securities of an entity other than a corporation, resulting from such reorganization, merger, or consolidation or the

combined voting power of the then outstanding Voting Stock of such corporation or other entity, and (iii) at least a majority

of the members of the board of directors of the corporation, or the body which is most analogous to the board of directors of

a corporation if not a corporation, resulting from such reorganization, merger, or consolidation were members of

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the Incumbent Board at the time of the initial agreement or initial action by the Board providing for such reorganization,

merger, or consolidation; or

(d) (i) the shareholders of the Company shall approve a complete liquidation or dissolution of the Company unless

such liquidation or dissolution is approved as part of a plan of liquidation and dissolution involving a sale or disposition of all

or substantially all of the assets of the Company to a corporation with respect to which, following such sale or other

disposition, all of the requirements of clauses (ii)(A), (B), and (C) of this subsection (d) are satisfied, or (ii) the Company

shall consummate the sale or other disposition of all or substantially all of the assets of the Company, other than to a

corporation or other entity, with respect to which, following such sale or other disposition, (A) 50% or more of the then

outstanding shares of common stock of such corporation, or common equity securities of an entity other than a corporation,

and the combined voting power of the Voting Stock of such corporation or other entity is then beneficially owned, directly

or indirectly, by all or substantially all of the Persons who were the Beneficial Owners of the outstanding Common Stock

immediately prior to such sale or other disposition in substantially the same proportion as their ownership, immediately

prior to such sale or other disposition, of the outstanding Common Stock, (B) no Person (excluding any Exempt Person

and any Person beneficially owning, immediately prior to such sale or other disposition, directly or indirectly, 20% or more

of the Common Stock then outstanding or 20% or more of the combined voting power of the Voting Stock of the Company

then outstanding) beneficially owns, directly or indirectly, 20% or more of the then outstanding shares of common stock of

such corporation, or common equity securities of an entity other than a corporation, and the combined voting power of the

then outstanding Voting Stock of such corporation or other entity, and (C) at least a majority of the members of the board of

directors of such corporation, or the body which is most analogous to the board of directors of a corporation if not a

corporation, were members of the Incumbent Board at the time of the initial agreement or initial action of the Board

providing for such sale or other disposition of assets of the Company.

Common Stock shall have the meaning set forth in the foregoing Plan.

Company shall have the meaning set forth in the foregoing Plan.

Election Contest shall mean a solicitation of proxies of the kind described in Rule 14a-12(c) under the Exchange Act.

Exchange Act shall mean the Securities Exchange Act of 1934, as amended.

Exempt Person shall mean any of the Company, any subsidiary of the Company, any employee benefit plan of the

Company or any subsidiary of the Company, and any Person organized, appointed, or established by the Company for or pursuant to the

terms of any such plan.

Exempt Rights shall mean any rights to purchase shares of Common Stock or other Voting Stock of the Company if at the

time of the issuance thereof such rights are not separable from such Common Stock or other Voting Stock (i.e., are not transferable

otherwise than in connection with a transfer of the underlying Common Stock or other Voting Stock), except upon the occurrence of a

contingency, whether such rights exist as of May 11. 2011 or are thereafter issued by the Company as a dividend on shares of Common

Stock or other Voting Securities or otherwise.

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Exempt Transaction shall mean an increase in the percentage of the outstanding shares of Common Stock or the

percentage of the combined voting power of the outstanding Voting Stock of the Company beneficially owned by any Person solely as a

result of a reduction in the number of shares of Common Stock then outstanding due to the repurchase of Common Stock or Voting

Stock by the Company, unless and until such time as (a) such Person or any Affiliate or Associate of such Person shall purchase or

otherwise become the Beneficial Owner of additional shares of Common Stock constituting 1% or more of the then outstanding shares

of Common Stock or additional Voting Stock representing 1% or more of the combined voting power of the then outstanding Voting

Stock, or (b) any other Person (or Persons) who is (or collectively are) the Beneficial Owner of shares of Common Stock constituting

1% or more of the then outstanding shares of Common Stock or Voting Stock representing 1% or more of the combined voting power of

the then outstanding Voting Stock shall become an Affiliate or Associate of such Person.

Person shall mean any individual, firm, corporation, partnership, association, trust, unincorporated organization, or other

entity.

Voting Stock shall mean, (i) with respect to a corporation, all securities of such corporation of any class or series that are

entitled to vote generally in the election of, or to appoint by contract, directors of such corporation (excluding any class or series that

would be entitled so to vote by reason of the occurrence of any contingency, so long as such contingency has not occurred) and (ii) with

respect to an entity which is not a corporation, all securities of any class or series that are entitled to vote generally in the election of, or

to appoint by contract, members of the body which is most analogous to the board of directors of a corporation.

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Exhibit 10.26.7

PERFORMANCE SHARE PROGRAM

FEBRUARY 5, 2013

FINAL PAYOUT FOR PERFORMANCE PERIOD VIII (PSP VIII TAIL)

PERFORMANCE SHARE UNIT

AWARD TERMS AND CONDITIONS

FOR GRANTEES ON THE CANADA PAYROLL

These Performance Share Unit Award Terms and Conditions describe terms and conditions of Performance Share Unit Awards, as part

of the ConocoPhillips Performance Share Program (Program), granted under the 2011 Omnibus Stock and Performance Incentive Plan

of ConocoPhillips (referred to as the Plan) by ConocoPhillips (Company) to you as an eligible employee (Grantee). These Terms and

Conditions, together with the Annual Award Summary given to each Grantee receiving an Award, form the Award Agreement (the

Agreement) relating to the Awards described. Subject to the Plan and this Agreement, the Company grants to the Grantee Performance

Share Units. Individual awards will be as set forth in the Annual Award Summary given to each Grantee to whom an Award is granted.

The Annual Award Summary for each Grantee is made a part of this Agreement with regard to such Grantee.

AWARD: Performance Stock Unit (PSU) Award granted by the Authorized Party under the provisions of the Plan. The PSUs

will be noted in a book entry account created for the Grantee.

PSU: A unit evidencing the right to receive one share of ConocoPhillips Stock, $0.01 par value, under the circumstances

described in these Terms and Conditions.

VOTING RIGHTS: The named owner of the PSUs has no voting rights for the units, but is considered the beneficial owner for all purposes

including ownership and control reports such as the annual proxy statement.

DIVIDEND EQUIVALENTS: Dividend equivalent payment, equal to the regular dividend payment as declared by the Board of Directors on an

equivalent number of common stock from time to time, will be made to the named owner of the units. Under current tax law, these

payments are taxable as compensation (i.e., ordinary income) in the year distributed.

RETIREMENT PLAN EARNINGS: The issuance of these PSUs does not constitute earnings under any retirement plan sponsored by a

ConocoPhillips company. The value of the units at the time the restrictions lapse also does not constitute earnings under any

retirement plan sponsored by a ConocoPhillips company. Neither the issuance of nor lapsing of restrictions on PSUs will have any

impact on any retirement plans or any other compensation plan sponsored by a ConocoPhillips company.

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TAX INFORMATION: This matter is more thoroughly covered in the document entitled “Tax Aspects of Performance Share Units,” however, in

general terms the value of these units is not considered taxable income until the restrictions lapse.

BENEFICIARY: In the event of the death of the named owner of these units prior to the lapsing of restrictions for other reasons, such restrictions

will lapse and shares of unrestricted common stock equal in number to the PSUs will be issued to the beneficiary designated by the

named owner of the units.

CHANGE OF CONTROL: If a Change of Control occurs, the PSUs shall vest and may not be forfeited but the restrictions on these shares will

lapse and unrestricted shares will be delivered to the Grantee upon Termination of Employment.

RESTRICTIONS: The following restrictions relate to the PSUs:

The PSUs will be held in escrow for the Grantee. As provided herein, the Grantee will have all rights of economic

ownership to such unit including the right to receive dividend equivalents, except that the Grantee shall not have the

right to sell, transfer, assign, or otherwise dispose of such units until the escrow is terminated (such restrictions being

known as the “Transfer Restrictions”).

Unless postponed pursuant to an effective election, as described in the sections on Initial Election and Subsequent

Election below, the escrow shall end on the earliest of any of the following occurrences, with Transfer Restrictions to

lapse and settlement be made as set forth in the section on Settlement below:

1. The Termination of the Grantee’s employment as a result of Layoff of the Grantee;

2. The Termination of the Grantee’s employment after attainment of age 55 and completion of 5 years of

service with the Company or its subsidiaries;

3. The Termination of the Grantee’s employment due to Death;

4. The Termination of the Grantee’s employment following Disability of the Grantee;

5. The Termination of the Grantee’s employment following a Change of Control; or

6. February 5, 2018.

In the absence of an effective election, as described in the sections on Initial Election and Subsequent Election below,

the Transfer Restrictions shall lapse and the PSUs (including any such that are awarded after the Separation from

Service of the Grantee) shall be settled in unrestricted stock of the Company on the date that is the later of (a) the end

of the escrow period and (b) the earliest of the Grantee’s death, February 5, 2018, or six months after the date of the

Grantee’s Separation from Service for a reason other than death.

INITIAL ELECTION: A Grantee may elect on an election form delivered to the Plan Administrator at a time set by the Plan Administrator (which

shall be on or before December 31, 2009) to have the escrow for the PSUs continue and the Transfer Restrictions applicable to

these PSUs continue and settlement in unrestricted stock postponed and made in either:

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1. one lump sum payment of unrestricted stock of the Company settled six months after Separation from

Service with the Company and its subsidiaries, or

2. in a series of annual installments, using a declining balance method, over a period of three, five, ten, or

fifteen years after Separation from Service with the Company and its subsidiaries.

In the absence of such an election, the escrow will end and settlement shall be made in one lump sum payment of

unrestricted stock of the Company on February 5, 2018.

SUBSEQUENT ELECTION: A Grantee may make an election to change the time or form of payment elected under the Initial Election section

above or the payment to be made under the Restrictions section above, but only if the following rules are satisfied:

1. The election to change the time or form of payment may not take effect until at least twelve months after

the date on which such election is made;

2. Payment under such election may not be made earlier than at least five years from the date the payment

would have otherwise been made or commenced;

3. An election may provide for either a lump sum payment or installment payments;

4. An election to receive payments in installments shall be treated as a single payment for purposes of these

rules;

5. Installment payments may be made only annually, over a period of from one to fifteen years as elected;

6. The election may not result in an impermissible acceleration of payment prohibited under section 409A of

the Internal Revenue Code;

7. No more than four such elections shall be permitted with respect to the PSUs subject to this Award; and

8. No payment may be made after the date that is twenty (20) years after the date of the Grantee’s Separation

from Service.

If an election under this section becomes effective, the escrow and the Transfer Restrictions applicable to the PSUs

shall continue until the time set in the election for the settlement of the PSUs as unrestricted stock of the Company.

SETTLEMENT: Upon termination of the escrow the Company shall, at the time stated above, deliver to each Grantee the Grantee’s shares as

common stock of the Company free of any restriction, unless the lapsing of restrictions has been delayed pursuant to a schedule

permitted under this Award. In all cases the Grantee will be responsible to pay all required withholding taxes associated with the

Award. The Grantee must pay any required withholding taxes by having shares equal in value to the applicable withholding taxes

withheld by the Company unless the Company, in its sole discretion deems that another method is allowable. The value of the

shares withheld for this purpose shall not exceed the minimum withholding amount required by the applicable laws and regulations.

The market value of the unrestricted shares received by the Grantee shall be deemed equal to the average of the

reported highest and lowest selling prices per share of such Stock as reported on the composite tape of the New York

Stock Exchange (or such other reporting system as shall be selected by the Committee) on the date the Award is

settled in

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unrestricted stock (or the last preceding date on which the Stock was traded, if no trades occurred on the applicable

date).

FORFEITURE: A Grantee’s right, title, and interest in Performance Share Units awarded under the PSP or derived from such Performance Share

Units, or the ownership thereof, shall be forfeited if the Grantee terminates employment prior to termination of the escrow period;

provided, however, any transfer between the Company and any Subsidiary, or between Subsidiaries at the request of the Company

or such Subsidiaries, shall not result in forfeiture.

DETRIMENTAL ACTIVITIES: If the Authorized Party determines that, subsequent to the grant of any Award, the Employee has engaged or is

engaging in any activity which, in the sole judgment of the Authorized Party, is or may be detrimental to the Company or a

subsidiary, the Authorized Party may cancel all or part of the Restricted Stock or Restricted Stock Units held in escrow pursuant

to the Award or Awards granted to that Employee.

If the Authorized Party, in its or his sole discretion, determines that the lapsing of restrictions on Restricted Stock or

Restricted Stock Units held in escrow pursuant to any Award has the possibility of violating any law, regulation, or

decree pertaining to the Company or Employee, the Authorized Party may freeze or suspend the Employee’s right to

settlement or payout of the Award until such time as the lapse of restrictions would no longer, in the sole discretion of

the Authorized Party, have the possibility of violating such law, regulation, or decree.

Notwithstanding anything herein to the contrary, this Award is subject to forfeiture or recoupment, in whole or in part,

under applicable law, including the Sarbanes-Oxley Act and the Dodd-Frank Act.

RECAPITALIZATION: Upon any change in the outstanding stock of the Company by reason of any stock dividend, stock split, reverse stock

split, recapitalization, reclassification, or other similar changes, the Committee shall make corresponding adjustments to the Total

Target Awards and Performance Share Awards.

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DEFINITIONS:

Capitalized terms not defined below shall have the meanings set forth in the Plan under which the Award is granted.

Authorized Party means the person who is authorized to approve an Award, exercise discretion, or take action under the Administrative

Procedure for the Performance Share Program and pursuant to the Program. With regard to Senior Officers, the Committee is the

Authorized Party. With regard to other Employees, the Chief Executive Officer, acting as the Special Equity Award Committee of the

Board of Directors of the Company, is the Authorized Party, although the Committee may act concurrently as the Authorized Party.

Award means any Performance Share Units granted to an Employee pursuant to such applicable terms, conditions, and limitations as the

Authorized Party may establish in order to fulfill the objectives of the Program.

Change of Control has the meaning set forth in Annex A to these Terms and Conditions.

Committee means the Human Resources and Compensation Committee of the Board of Directors of the Company, or any successor

committee to it.

Company means ConocoPhillips, a Delaware corporation.

Disability means a disability for which the employee in question has been determined to be entitled to either (i) benefits under the

applicable plan of long-term disability of the Company or its subsidiaries or (ii) disability benefits under the Social Security Act. In the

absence of any such determination, the Authorized Party may make a determination that the employee has a Disability.

Fair Market Value means, as of a particular date, the mean between the highest and lowest sales price per share of such Stock on the

consolidated transaction reporting system for the principal national securities exchange on which shares of Stock are listed on that date,

or, if there shall have been no such sale so reported on that date, on the next preceding date on which such a sale was so reported, or, at

the discretion of the Committee, the price prevailing on the exchange at a designated time.

Grant Price means the Fair Market Value for one share of Stock as of the date of the grant of an Award. Grant price is not adjusted for

any restrictions applicable to the Award.

Layoff means an applicable Termination of Employment due to layoff under the ConocoPhillips Severance Pay Plan, the ConocoPhillips

Executive Severance Plan, or the ConocoPhillips Key Employee Change in Control Severance Plan, or layoff or redundancy under any

similar layoff or redundancy plan which the Company or its subsidiaries may adopt from time to time. If all or any portion of the benefits

under the redundancy or layoff plan are contingent on the employee’s signing a general release of liability, such Termination shall not be

considered as a “Layoff” for purposes of this Award unless the employee executes and does not revoke a general release of liability,

acceptable to the Company, under the terms of such layoff or redundancy plan. In order to be considered a layoff for purposes of this

Award, the Termination of Employment must also be considered a Separation from Service.

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Participating Company includes ConocoPhillips and its 100% owned subsidiaries, including both those directly owned and those owned

through subsidiaries, whose participation has been approved by the Authorized Party.

Performance Share Unit or PSU means the type of restricted stock unit issued under the Performance Share Program (as determined

by the Authorized Party) that is subject to forfeiture provisions or that has certain restrictions attached to the ownership thereof.

Restricted Stock Unit means a unit equal to one share of Stock (as determined by the Authorized Party) that is subject to forfeiture

provisions or that has certain restrictions attached to the ownership thereof.

Retirement means Termination at age 55 or older with a minimum of 5 years service with a Participating Company; provided, however,

that with regard to an Employee not on the United States payroll, the CEO may approve the use of a different definition. Service is

defined by the policies of the Participating Company.

Senior Officer means the Chairman of the Board, the CEO, all other executive officers of the Company (determined in accordance

with the Company’s custom and practice pursuant to section 16(b) of the Securities Exchange Act of 1934, as amended), all other

employees of the Company who report directly to the CEO and whose salary grade is 23 or higher, and all other employees of the

Company whose salary grade is 26 or higher.

Stock means shares of common stock of the Company, par value $.01. Stock may also be referred to as “Common Stock.”

Termination, Termination of Employment, and Separation from Service each mean “separation from service” as that term is used in

section 409A of the Internal Revenue Code.

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Annex A

Change of Control

The following definitions apply to the Change of Control provision in Paragraph 10 of the Plan.

Affiliate shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the Exchange

Act, as in effect at the time of determination.

Associate shall mean, with reference to any Person, (a) any corporation, firm, partnership, association, unincorporated

organization or other entity (other than the Company or a subsidiary of the Company) of which such Person is an officer or general

partner (or officer or general partner of a general partner) or is, directly or indirectly, the Beneficial Owner of 10% or more of any class

of equity securities, (b) any trust or other estate in which such Person has a substantial beneficial interest or as to which such Person

serves as trustee or in a similar fiduciary capacity and (c) any relative or spouse of such Person, or any relative of such spouse, who has

the same home as such Person.

Beneficial Owner shall mean, with reference to any securities, any Person if:

(a) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, is the “beneficial owner” of (as

determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act, as in effect at the time of

determination) such securities or otherwise has the right to vote or dispose of such securities;

(b) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, has the right or obligation to acquire

such securities (whether such right or obligation is exercisable or effective immediately or only after the passage of time or the

occurrence of an event) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the

exercise of conversion rights, exchange rights, other rights, warrants or options, or otherwise; provided, however, that a Person

shall not be deemed the Beneficial Owner of, or to “beneficially own,” (i) securities tendered pursuant to a tender or exchange

offer made by such Person or any of such Person’s Affiliates or Associates until such tendered securities are accepted for

purchase or exchange or (ii) securities issuable upon exercise of Exempt Rights; or

(c) such Person or any of such Person’s Affiliates or Associates (i) has any agreement, arrangement or understanding

(whether or not in writing) with any other Person (or any Affiliate or Associate thereof) that beneficially owns such securities for

the purpose of acquiring, holding, voting (except as set forth in the proviso to subsection (a) of this definition) or disposing of such

securities or (ii) is a member of a group (as that term is used in Rule 13d-5(b) of the General Rules and Regulations under the

Exchange Act) that includes any other Person that beneficially owns such securities;

provided, however, that nothing in this definition shall cause a Person engaged in business as an underwriter of securities to be the

Beneficial Owner of, or to beneficially own, any securities acquired through such Person’s participation in good faith in a firm

commitment underwriting until the expiration of 40 days after the date of such acquisition. For purposes hereof, “voting” a security shall

include voting, granting a proxy, consenting or making a request or demand relating to corporate action (including, without limitation, a

demand for a shareholder list, to call a shareholder meeting or to inspect

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corporate books and records) or otherwise giving an authorization (within the meaning of Section 14(a) of the Exchange Act) in respect

of such security.

The terms beneficially own and beneficially owning shall have meanings that are correlative to this definition of the term

Beneficial Owner.

Board shall have the meaning set forth in the foregoing Plan.

Change of Control shall mean any of the following occurring on or after May 11, 2011:

(a) any Person (other than an Exempt Person) shall become the Beneficial Owner of 20% or more of the shares of

Common Stock then outstanding or 20% or more of the combined voting power of the Voting Stock of the Company then

outstanding; provided, however, that no Change of Control shall be deemed to occur for purposes of this subsection (a) if such

Person shall become a Beneficial Owner of 20% or more of the shares of Common Stock or 20% or more of the combined voting

power of the Voting Stock of the Company solely as a result of (i) an Exempt Transaction or (ii) an acquisition by a Person

pursuant to a reorganization, merger or consolidation, if, following such reorganization, merger or consolidation, the conditions

described in clauses (i), (ii) and (iii) of subsection (c) of this definition are satisfied;

(b) individuals who, as of May 11, 2011, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at

least a majority of the Board; provided, however, that any individual becoming a director subsequent to May 11, 2011 whose

election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors

then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board;

provided, further, that there shall be excluded, for this purpose, any such individual whose initial assumption of office occurs as a

result of any actual or threatened Election Contest that is subject to the provisions of Rule 14a-11 of the General Rules and

Regulations under the Exchange Act;

(c) the Company shall consummate a reorganization, merger, or consolidation, in each case, unless, following such

reorganization, merger, or consolidation, (i) 50% or more of the then outstanding shares of common stock of the corporation, or

common equity securities of an entity other than a corporation, resulting from such reorganization, merger, or consolidation and

the combined voting power of the then outstanding Voting Stock of such corporation or other entity are beneficially owned,

directly or indirectly, by all or substantially all of the Persons who were the Beneficial Owners of the outstanding Common

Stock immediately prior to such reorganization, merger, or consolidation in substantially the same proportions as their ownership,

immediately prior to such reorganization, merger, or consolidation, of the outstanding Common Stock, (ii) no Person (excluding

any Exempt Person or any Person beneficially owning, immediately prior to such reorganization, merger, or consolidation,

directly or indirectly, 20% or more of the Common Stock then outstanding or 20% or more of the combined voting power of the

Voting Stock of the Company then outstanding) beneficially owns, directly or indirectly, 20% or more of the then outstanding

shares of common stock of the corporation, or common equity securities of an entity other than a corporation, resulting from

such reorganization, merger, or consolidation or the combined voting power of the then outstanding Voting Stock of such

corporation or other entity, and (iii) at least a majority of the members of the board of directors of the corporation, or the body

which is most analogous to the board of directors of a corporation if not a corporation, resulting from such reorganization, merger,

or consolidation were members of

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the Incumbent Board at the time of the initial agreement or initial action by the Board providing for such reorganization, merger,

or consolidation; or

(d) (i) the shareholders of the Company shall approve a complete liquidation or dissolution of the Company unless such

liquidation or dissolution is approved as part of a plan of liquidation and dissolution involving a sale or disposition of all or

substantially all of the assets of the Company to a corporation with respect to which, following such sale or other disposition, all of

the requirements of clauses (ii)(A), (B), and (C) of this subsection (d) are satisfied, or (ii) the Company shall consummate the sale

or other disposition of all or substantially all of the assets of the Company, other than to a corporation or other entity, with respect

to which, following such sale or other disposition, (A) 50% or more of the then outstanding shares of common stock of such

corporation, or common equity securities of an entity other than a corporation, and the combined voting power of the Voting Stock

of such corporation or other entity is then beneficially owned, directly or indirectly, by all or substantially all of the Persons who

were the Beneficial Owners of the outstanding Common Stock immediately prior to such sale or other disposition in substantially

the same proportion as their ownership, immediately prior to such sale or other disposition, of the outstanding Common Stock,

(B) no Person (excluding any Exempt Person and any Person beneficially owning, immediately prior to such sale or other

disposition, directly or indirectly, 20% or more of the Common Stock then outstanding or 20% or more of the combined voting

power of the Voting Stock of the Company then outstanding) beneficially owns, directly or indirectly, 20% or more of the then

outstanding shares of common stock of such corporation, or common equity securities of an entity other than a corporation, and

the combined voting power of the then outstanding Voting Stock of such corporation or other entity, and (C) at least a majority of

the members of the board of directors of such corporation, or the body which is most analogous to the board of directors of a

corporation if not a corporation, were members of the Incumbent Board at the time of the initial agreement or initial action of the

Board providing for such sale or other disposition of assets of the Company.

Common Stock shall have the meaning set forth in the foregoing Plan.

Company shall have the meaning set forth in the foregoing Plan.

Election Contest shall mean a solicitation of proxies of the kind described in Rule 14a-12(c) under the Exchange Act.

Exchange Act shall mean the Securities Exchange Act of 1934, as amended.

Exempt Person shall mean any of the Company, any subsidiary of the Company, any employee benefit plan of the Company or

any subsidiary of the Company, and any Person organized, appointed, or established by the Company for or pursuant to the terms of any

such plan.

Exempt Rights shall mean any rights to purchase shares of Common Stock or other Voting Stock of the Company if at the time of

the issuance thereof such rights are not separable from such Common Stock or other Voting Stock (i.e., are not transferable otherwise

than in connection with a transfer of the underlying Common Stock or other Voting Stock), except upon the occurrence of a

contingency, whether such rights exist as of May 11. 2011 or are thereafter issued by the Company as a dividend on shares of Common

Stock or other Voting Securities or otherwise.

Effective 2/5/2013

 - 9 - 
Exempt Transaction shall mean an increase in the percentage of the outstanding shares of Common Stock or the percentage of

the combined voting power of the outstanding Voting Stock of the Company beneficially owned by any Person solely as a result of a

reduction in the number of shares of Common Stock then outstanding due to the repurchase of Common Stock or Voting Stock by the

Company, unless and until such time as (a) such Person or any Affiliate or Associate of such Person shall purchase or otherwise become

the Beneficial Owner of additional shares of Common Stock constituting 1% or more of the then outstanding shares of Common Stock

or additional Voting Stock representing 1% or more of the combined voting power of the then outstanding Voting Stock, or (b) any other

Person (or Persons) who is (or collectively are) the Beneficial Owner of shares of Common Stock constituting 1% or more of the then

outstanding shares of Common Stock or Voting Stock representing 1% or more of the combined voting power of the then outstanding

Voting Stock shall become an Affiliate or Associate of such Person.

Person shall mean any individual, firm, corporation, partnership, association, trust, unincorporated organization, or other entity.

Voting Stock shall mean, (i) with respect to a corporation, all securities of such corporation of any class or series that are entitled

to vote generally in the election of, or to appoint by contract, directors of such corporation (excluding any class or series that would be

entitled so to vote by reason of the occurrence of any contingency, so long as such contingency has not occurred) and (ii) with respect to

an entity which is not a corporation, all securities of any class or series that are entitled to vote generally in the election of, or to appoint

by contract, members of the body which is most analogous to the board of directors of a corporation.

Effective 2/5/2013

 - 10 - 
Exhibit 10.26.8

RESTRICTED STOCK PROGRAM

FEBRUARY 5, 2013

KEY EMPLOYEE AWARD

TERMS AND CONDITIONS

This Key Employee Award Terms and Conditions describes terms and conditions of Restricted Stock or Restricted Stock Unit Awards,

as part of the ConocoPhillips Restricted Stock Program (Program), granted under the 2011 Omnibus Stock and Performance Incentive

Plan of ConocoPhillips (referred to as the Plan) by ConocoPhillips (Company) to certain eligible Employees (Employees). These Terms

and Conditions, together with the Annual Award Summary given to each Employee receiving an Award, form the Award Agreement

(the Agreement) relating to the Awards described. The Agreement covers both Restricted Stock and Restricted Stock Units, and the

term Employee covers recipients of Awards made either in Restricted Stock or Restricted Stock Units.

1. Type and Size of Grant. Subject to the Plans and this Agreement, the Company grants to certain eligible Employees Restricted

Stock or Restricted Stock Units. Individual awards will be as set forth in the Annual Award Summary given to each Employee to

whom an Award is granted. The Annual Award Summary for each Employee is made a part of this Agreement with regard to

such Employee.

2. Grant Date, Price, and Plan. The Grant Date is February 5, 2013. The Grant Price is set forth on the Award Summary

given to each Employee to whom an Award is granted. Awards are made under the 2011 Omnibus Stock and Performance

Incentive Plan.

3. Restrictions, Forfeiture, and Lapse of Restrictions. The Restricted Stock or Restricted Stock Units subject hereto may be

canceled or forfeited as set forth herein. Except as otherwise noted in this Agreement, the following summary table describes

restrictions and terms, forfeiture, and lapse of restrictions, subject to the more detailed provisions set forth below:

Summary Table

Summary of Termination Rules

Status

 

Termination

Date 

Forfeiture or Lapsing of Restrictions

Retirement (age 55 and 5

years of service)

 

Prior to 6

months from

grant date 

Canceled upon Termination

 

6 months from

grant date &

after 

Restrictions lapse on Termination date

Layoff 

Prior to 6

months from

grant date 

Canceled upon Termination

 

6 months to 1

year from grant

date 

Award is prorated and restrictions on remaining stock/units lapse on Termination

date

Effective 2/5/2013 Page 1 of 13 
 

1 year from

grant date &

after 

Restrictions lapse on Termination date

Disability

 

Any date after

grant date 

Restrictions lapse on Termination date

Death

 

Any date after

grant date 

Restrictions lapse on Termination date

Divestitures, outsourcing, and

moves to joint ventures 

Any date after

grant date 

Canceled upon Termination, unless approval otherwise

All other Terminations Canceled upon Termination

(a) Restrictions and Terms.

(i) The Award shall be held in escrow by the Company until the lapsing of restrictions placed upon the Award. The

Employee shall not have the right to sell, transfer, assign, or otherwise dispose of Restricted Stock or Restricted Stock

Units granted in an Award until the escrow is terminated. Except as set forth below, the Award shall be forfeited and

the related Restricted Stock or Restricted Stock Units canceled upon the Employee’s Termination of Employment

with the Company prior to the lapsing of restrictions. Restrictions shall lapse on the Restricted Stock or Restricted

Stock Units granted in an Award on the third anniversary of the Grant Date. Upon the lapsing of restrictions, the

number of shares of unrestricted Stock equal to the number of shares of Restricted Stock or Restricted Stock Units

for which the restrictions have so lapsed shall be registered in the Employee’s name, and the related shares of

Restricted Stock or Restricted Stock Units shall be canceled; provided, however, that the Administrator may choose

instead to issue any Restricted Stock with the restrictions removed, rather than cancel such Restricted Stock and issue

unrestricted Stock; and further provided, however, that in places where it is determined by the Administrator that

payout in the form of unrestricted Stock is prohibited by law, regulation, or decree, or where the cost of legal

compliance to issue the unrestricted Stock would be unreasonably expensive, the Fair Market Value of such

unrestricted Stock shall be paid in cash instead of settlement of the Award in unrestricted Stock. Cash payouts are only

permitted where such legal restrictions exist. Settlement of the Award in unrestricted Stock or cash payout, if any,

shall be made upon the lapsing of restrictions on the Award, but, in any event, shall be made no later than March 15 of

the year following the year in which such restrictions lapse.

(ii) Restricted Stock Units do not have any voting rights or other rights generally associated with Stock, and are merely an

obligation of the Company to make settlement in accordance with the terms and conditions applicable to such

Restricted Stock Units. Restricted Stock Units granted to Employees who are resident in the United States or the

United Kingdom on the Grant Date shall accrue a dividend equivalent at such times as an ordinary quarterly cash

dividend is paid on the Stock of the Company, which dividend equivalent shall be paid in cash to the Employee to

whom the Award was made. Restricted Stock Units granted to Employees other than those described in the previous

sentence shall not accrue a dividend equivalent. Payment of a dividend equivalent, if any, shall be made on the first day

of the third month of each calendar quarter (or, if the New York Stock Exchange is not open on such day, the first day

that the New York Stock Exchange is open thereafter), and, in any event, shall be made no later than March 15 of the

year following the year in which the ordinary quarterly cash dividend is paid.

(iii) When an Award is made of Restricted Stock, such Restricted Stock will be held in escrow for the Employee to whom

the Award is made. The Employee to whom the Award is made will have all rights of ownership to such stock

including, but not limited to, voting rights and the right to receive dividends, except that the Employee to whom the

Effective 2/5/2013 Page 2 of 13 
Award is made shall not have the right to sell, transfer, assign, or otherwise dispose of such shares until the escrow is

terminated. The escrow shall end upon, and to the extent of, the lapsing of restrictions.

(b) Termination of Employment.

(i) General Rule for Termination. If, prior to the date on which restrictions lapse in accordance with the schedule set forth

in the Award, the Employee’s employment with a Participating Company shall be terminated for any reason except

death, Disability, Retirement, or Layoff, any Restricted Stock or Restricted Stock Units remaining in escrow pursuant

to such Award shall be canceled and all rights thereunder shall cease; provided, however, that the Authorized Party

may, in its or his sole discretion, determine that all or any portion of an Award shall not be canceled due to Termination

of Employment.

(ii) Layoff Within Six Months. If, prior to a date six months from the date an Award is granted, the Employee’s

employment with a Participating Company shall be terminated by reason of Layoff, such Award shall be canceled and

all rights thereunder shall cease.

(iii) Layoff Within One Year. If, on or after a date six months from the date an Award is granted but prior to a date one year

from the date an Award is granted, the Employee’s employment with a Participating Company shall be terminated by

reason of Layoff, the Employee shall retain a prorated number of the Award shares or units granted. The number of

Award shares or units retained will be computed by multiplying the original number of Award shares or units granted

by a fraction, the numerator of which is the number of full months of employment from the first day of the month in

which the Award was granted until the date the employee is terminated and the denominator of which is 12. Such

calculation shall be rounded down to the nearest whole share. In such case, the restrictions on the prorated Award shall

lapse on the date of Termination of the Employee from the employ of the Company and its subsidiaries, and settlement

shall be made in accordance with the settlement provisions above.

(iv) Layoff After One Year. If, on or after a date one year from the date an Award is granted, the Employee’s employment

with a Participating Company shall be terminated by reason of Layoff, the Employee shall retain all rights provided by

the Award at the time of such Termination of Employment. In such case, the restrictions on the Award shall lapse on

the date of Termination of the Employee from the employ of the Company and its subsidiaries, and settlement shall be

made in accordance with the settlement provisions above.

(v) Retirement After Six Months. If, on or after a date six months after the Grant Date of an Award, the Employee’s

employment with a Participating Company shall be terminated by reason of Retirement, the Employee shall retain all

rights provided by the Award at the time of such Termination of Employment. In such case, the restrictions on the

Award shall lapse on the date of Termination of the Employee from the employ of the Company and its subsidiaries,

and settlement shall be made in accordance with the settlement provisions above.

(vi) Disability. If, after the date the Award is granted, an Employee shall terminate employment following Disability of the

Employee, the Employee shall retain all rights provided by the Award at the time of such Termination of

Employment. In such case, the restrictions on the Award shall lapse on the date of Termination of Employment from

the employ of the Company and its subsidiaries, and settlement shall be made in accordance with the settlement

provisions above.

(vii) Death. If, after the date an Award is granted, a Employee shall die while in the employ of a Participating Company , or

after Termination of Employment by reason of

Effective 2/5/2013 Page 3 of 13 
Retirement, Disability, or Layoff (and prior to the cancellation of the Award), the executor or administrator of the

estate of the Employee or the person or persons to whom the Award shall have been validly transferred by the

executor or the administrator pursuant to will or the laws of descent and distribution shall have the right to settlement

of the Award to the same extent the Employee would have, had the Employee not died. In such case, the restrictions

on the Award shall lapse upon the determination of death by the Administrator, and settlement shall be made in

accordance with the settlement provisions above. No transfer of an Award, or of the unrestricted Stock or other

proceeds of an Award, by the Employee by will or by the laws of descent and distribution shall be effective to bind the

Company unless the Administrator shall have been furnished with written notice thereof and a copy of the will and

such other evidence as the Administrator may deem necessary to establish the validity of the transfer and the

acceptance by the transferee or transferees of the terms and conditions of such Award.

(viii) Transfers and Leaves. Transfer of employment between Participating Companies shall not constitute Termination of

Employment for the purpose of any Award granted under the Program. Whether any leave of absence shall constitute

Termination of Employment for the purposes of any Award granted under the Program shall be determined by the

Administrator, in each case in accordance with applicable law and by application of the policies and procedures adopted

by the Company in relation to such leave of absence.

(ix) Divestiture, Outsourcing, or Move to Joint Venture. If, after the date the Award is granted, a Employee ceases to be

employed by Participating Company as a result of (a) the outsourcing of a function, (b) the sale or transfer of all or a

portion of the equity interest of such Participating Company (removing it from the controlled group of companies of

which the Company is a part), (c) the sale of all or substantially all of the assets of such Participating Company to

another employer outside of the controlled group of corporations (whether the Employee is offered employment or

accepts employment with the other employer), (d) the Termination of the Employee by a Participating Company

followed by employment within a reasonable time with a company or other entity in which the Company owns,

directly or indirectly, at least a 50% interest, prior to exercise of an Award, or (e) any other sale of assets determined by

the Authorized Party to be considered a divestiture under this program, the Authorized Party may, in its or his sole

discretion, determine that all or a portion of any such Award shall not be canceled. In such cases, the restrictions on the

Award shall lapse on the date of Termination of the Employee from the employ of the Company and its subsidiaries,

and settlement shall be made in accordance with the settlement provisions above.

(x) Change of Control. In the event of a Change of Control, as defined hereafter, unless explicitly provided otherwise in

the applicable Award Agreement, all restrictions and other limitations applicable to any Restricted Stock or Restricted

Stock Units granted in any Award shall lapse. With regard to such Restricted Stock, it shall become free of all

restrictions and become fully vested and transferable to the full extent of the original grant. With regard to such

Restricted Stock Units, the Employee shall be vested in the Restricted Stock Units and the Restricted Stock Units

shall be non-forfeitable upon the Change of Control. Settlement in unrestricted Stock or cash shall be made at the

same times and upon the same events as it would otherwise have been made in accordance with the settlement

provisions above.

(xi) Notwithstanding anything herein to the contrary, in the event that this Award or the dividend equivalents associated

with this Award are includible in income pursuant to section 409A of the Internal Revenue Code, settlement of the

Award or any other distribution hereunder due to Separation from Service with the Company and its subsidiaries shall

not be made to a “specified employee” (as that term is defined in section 409A(a)(2)(B)(i)) prior to six months after the

specified employee’s Separation

Effective 2/5/2013 Page 4 of 13 
from Service from the Company and its subsidiaries (or, if earlier, the date of death of the specified employee).

(c) Detrimental Activities and Suspension of Award.

(i) If the Authorized Party determines that, subsequent to the grant of any Award, the Employee has engaged or is

engaging in any activity which, in the sole judgment of the Authorized Party, is or may be detrimental to the Company

or a subsidiary, the Authorized Party may cancel all or part of the Restricted Stock or Restricted Stock Units held in

escrow pursuant to the Award or Awards granted to that Employee.

(ii) If the Authorized Party, in its or his sole discretion, determines that the lapsing of restrictions on Restricted Stock or

Restricted Stock Units held in escrow pursuant to any Award has the possibility of violating any law, regulation, or

decree pertaining to the Company or Employee, the Authorized Party may freeze or suspend the Employee’s right to

settlement or payout of the Award until such time as the lapse of restrictions would no longer, in the sole discretion of

the Authorized Party, have the possibility of violating such law, regulation, or decree.

(iii) Notwithstanding anything herein to the contrary, any Award is subject to forfeiture or recoupment, in whole or in part,

under applicable law, including the Sarbanes-Oxley Act and the Dodd-Frank Act.

4. Assignment of Award Upon Death. Rights under the Plans and this Agreement cannot be assigned or transferred other than by

(i) will or (ii) the laws of descent and distribution.

5. Tax Withholding. In all cases the Employee will be responsible to pay all required withholding taxes associated with an Award.

Should a withholding tax obligation arise with regard to an Award or the lapsing of restrictions on Restricted Stock or Restricted

Stock Units granted in an Award, the withholding tax may be satisfied by withholding shares of Stock. The value of the shares of

Stock withheld for this purpose shall not exceed the minimum withholding amount required by applicable laws and regulations. In

cases where a withholding tax obligation arises prior to the lapse of restrictions on Restricted Stock or Restricted Stock Units

granted in an Award, the withholding tax may be satisfied instead by payment of cash by the Employee. Payment of cash shall not

be allowed unless the Employee has elected to make such payment by payroll withholding over a period of six months following

the date the obligation shall arise, which election must be made within thirty days of the Grant Date of the relevant Award. If any

interest is required under local laws, regulations, or decrees to be charged on or imputed against the payroll withholding, the

Employee shall be responsible for paying such interest, which shall be withheld from pay over the same six-month period. In

cases where payment by payroll withholding cannot be made due to circumstances arising after the election or where the

Administrator has determined that such withholding would violate any applicable law, regulation, or decree, shares of Stock shall

be withheld instead. When necessary, lapsing of restrictions may be accelerated by the Authorized Party to the extent necessary to

provide shares of Stock to satisfy any withholding tax obligation. This withholding tax obligation includes, but is not limited to,

federal, state, and local taxes, including applicable non-U.S. taxes such as U.K. PAYE.

6. Shareholder Rights for Restricted Stock Units. The Employee shall not have the rights of a shareholder until the Restricted

Stock Unit has been canceled and ownership of shares of Stock has been transferred to the Employee. As described above, the

Company may pay dividend equivalents with regard to Restricted Stock Units in certain circumstances.

7. Certain Adjustments. In the event certain corporate transactions, recapitalizations, or stock splits occur while Restricted Stock

or Restricted Stock Units are outstanding, the Grant Price and the number of shares of Restricted Stock or Restricted Stock Units

shall be correspondingly adjusted.

Effective 2/5/2013 Page 5 of 13 
8. Relationship to the Plan. In addition to the terms and conditions described in this Agreement, Awards are subject to all other

applicable provisions of the Plan. The decisions of the Committee with respect to questions arising as to the interpretation of the

Plan or this Agreement and as to findings of fact, shall be final, conclusive, and binding.

9. No Employment Guarantee. No provision of this Agreement shall confer any right upon the Employee to continued

employment with any Participating Company.

10. Governing Law. This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of

Delaware.

11. Amendment. Without the consent of the Employee, this Agreement may be amended or supplemented (i) to cure any ambiguity

or to correct or supplement any provision herein which may be defective or inconsistent with any other provision herein, or (ii) to

add to the covenants and agreements of the Company for the benefit of an Employee or to add to the rights of an Employee or to

surrender any right or power reserved to or conferred upon the Company in this Agreement, provided, in each case, that such

changes or corrections shall not adversely affect the rights of the Employee with respect to the grant of an Award evidenced

hereby without the Employee’s consent, or (iii) to make such other changes as the Company, upon advice of counsel, determines

are necessary or advisable because of the adoption or promulgation of, or change in or of the interpretation of, any law or

governmental rule or regulation, including any applicable federal or state securities or tax laws.

Effective 2/5/2013 Page 6 of 13 
DEFINITIONS

Capitalized terms not defined below shall have the meanings set forth in the Plan.

Authorized Party means the person who is authorized to approve an Award, exercise discretion or take action under the Administrative

Procedure for the Restricted Stock Program and pursuant to the Program. With regard to Senior Officers, the Committee is the

Authorized Party. With regard to other Employees, the Chief Executive Officer, acting as the Special Equity Award Committee of the

Board of Directors of the Company, is the Authorized Party, although the Committee may act concurrently as the Authorized Party.

Award means any Restricted Stock or Restricted Stock Units granted to an Employee pursuant to such applicable terms, conditions, and

limitations as the Authorized Party may establish in order to fulfill the objectives of the Program.

Change of Control has the meaning set forth in Attachment A to these Terms and Conditions.

Committee means the Human Resources and Compensation Committee of the Board of Directors of the Company, or any successor

committee to it.

Company means ConocoPhillips, a Delaware corporation.

Disability means a disability for which the employee in question has been determined to be entitled to either (i) benefits under the

applicable plan of long-term disability of the Company or its subsidiaries or (ii) disability benefits under the Social Security Act. In the

absence of any such determination, the Authorized Party may make a determination that the employee has a Disability.

Fair Market Value means, as of a particular date, the mean between the highest and lowest sales price per share of such Stock on the

consolidated transaction reporting system for the principal national securities exchange on which shares of Stock are listed on that date,

or, if there shall have been no such sale so reported on that date, on the next preceding date on which such a sale was so reported, or, at

the discretion of the Committee, the price prevailing on the exchange at a designated time.

Grant Price means the Fair Market Value for one share of Stock as of the date of the grant of an Award. Grant price is not adjusted for

any restrictions applicable to the Award.

Layoff means an applicable Termination of Employment due to layoff under the ConocoPhillips Severance Pay Plan, the

ConocoPhillips Executive Severance Plan, or the ConocoPhillips Key Employee Change in Control Severance Plan, or layoff or

redundancy under any similar layoff or redundancy plan which the Company or its subsidiaries may adopt from time to time. If all or any

portion of the benefits under the redundancy or layoff plan are contingent on the employee’s signing a general release of liability, such

Termination shall not be considered as a “Layoff” for purposes of this Award unless the employee executes and does not revoke a

general release of liability, acceptable to the Company, under the terms of such layoff or redundancy plan. In order to be considered a

layoff for purposes of this Award, the Termination of Employment must also be considered a Separation from Service.

Participating Company includes ConocoPhillips and its 100% owned subsidiaries, including both those directly owned and those owned

through subsidiaries, whose participation has been approved by the Authorized Party.

Restricted Stock means shares of Stock that have certain restrictions attached to the ownership thereof.

Restricted Stock Unit means a unit equal to one share of Stock (as determined by the Authorized Party)

Effective 2/5/2013 Page 7 of 13 
that is subject to forfeiture provisions or that has certain restrictions attached to the ownership thereof.

Retirement means Termination at age 55 or older with a minimum of 5 years service with a Participating Company; provided, however,

that with regard to an Employee not on the United States payroll, the CEO may approve the use of a different definition. Service is

defined by the policies of the Participating Company.

Senior Officer means the Chairman of the Board, the CEO, all other executive officers of the Company (determined in accordance

with the Company’s custom and practice pursuant to section 16(b) of the Securities Exchange Act of 1934, as amended), all other

employees of the Company who report directly to the CEO and whose salary grade is 23 or higher, and all other employees of the

Company whose salary grade is 26 or higher.

Separation from Service means “separation from service” as that term is used in section 409A of the Internal Revenue Code.

Stock means shares of common stock of the Company, par value $.01. Stock may also be referred to as “Common Stock.”

Termination and Termination of Employment mean cessation of employment with the Participating Companies, determined in

accordance with the policies and practices of the Participating Company for whom the Employee was last performing services.

Effective 2/5/2013 Page 8 of 13 
Attachment A

Change of Control

The following definitions apply to the Change of Control provision in Paragraph 10 of the Plan.

Affiliate shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the

Exchange Act, as in effect at the time of determination.

Associate shall mean, with reference to any Person, (a) any corporation, firm, partnership, association, unincorporated

organization or other entity (other than the Company or a subsidiary of the Company) of which such Person is an officer or general

partner (or officer or general partner of a general partner) or is, directly or indirectly, the Beneficial Owner of 10% or more of any class

of equity securities, (b) any trust or other estate in which such Person has a substantial beneficial interest or as to which such Person

serves as trustee or in a similar fiduciary capacity and (c) any relative or spouse of such Person, or any relative of such spouse, who has

the same home as such Person.

Beneficial Owner shall mean, with reference to any securities, any Person if:

(a) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, is the “Beneficial Owner” of (as

determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act, as in effect at the time of

determination) such securities or otherwise has the right to vote or dispose of such securities;

(b) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, has the right or obligation to acquire

such securities (whether such right or obligation is exercisable or effective immediately or only after the passage of time or the

occurrence of an event) pursuant to any agreement, arrangement or understanding (whether or not in writing) or upon the

exercise of conversion rights, exchange rights, other rights, warrants or options, or otherwise; provided, however, that a Person

shall not be deemed the Beneficial Owner of, or to “beneficially own,” (i) securities tendered pursuant to a tender or exchange

offer made by such Person or any of such Person’s Affiliates or Associates until such tendered securities are accepted for

purchase or exchange or (ii) securities issuable upon exercise of Exempt Rights; or

(c) such Person or any of such Person’s Affiliates or Associates (i) has any agreement, arrangement or understanding

(whether or not in writing) with any other Person (or any Affiliate or Associate thereof) that beneficially owns such securities for

the purpose of acquiring, holding, voting (except as set forth in the proviso to subsection (a) of this definition) or disposing of such

securities or (ii) is a member of a group (as that term is used in Rule 13d-5(b) of the General Rules and Regulations under the

Exchange Act) that includes any other Person that beneficially owns such securities;

provided, however, that nothing in this definition shall cause a Person engaged in business as an underwriter of securities to be the

Beneficial Owner of, or to beneficially own, any securities acquired through such Person’s participation in good faith in a firm

commitment underwriting until the expiration of 40 days after the date of such acquisition. For purposes hereof, “voting” a security shall

include voting, granting a proxy, consenting or making a request or demand relating to corporate action (including, without limitation, a

demand for a shareholder list, to call a shareholder meeting or to inspect corporate books and records) or otherwise giving an

authorization (within the meaning of Section 14(a) of the Exchange Act) in respect of such security.

The terms beneficially own and beneficially owning shall have meanings that are correlative to this definition of the

term Beneficial Owner.

Effective 2/5/2013 Page 9 of 13 
Board shall have the meaning set forth in the foregoing Plan.

Change of Control shall mean any of the following occurring on or after May 11, 2011:

(a) any Person (other than an Exempt Person) shall become the Beneficial Owner of 20% or more of the shares of

Common Stock then outstanding or 20% or more of the combined voting power of the Voting Stock of the Company then

outstanding; provided, however, that no Change of Control shall be deemed to occur for purposes of this subsection (a) if such

Person shall become a Beneficial Owner of 20% or more of the shares of Common Stock or 20% or more of the combined voting

power of the Voting Stock of the Company solely as a result of (i) an Exempt Transaction or (ii) an acquisition by a Person

pursuant to a reorganization, merger or consolidation, if, following such reorganization, merger or consolidation, the conditions

described in clauses (i), (ii) and (iii) of subsection (c) of this definition are satisfied;

(b) individuals who, as of May 11, 2011, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at

least a majority of the Board; provided, however, that any individual becoming a director subsequent to May 11, 2011 whose

election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors

then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board;

provided, further, that there shall be excluded, for this purpose, any such individual whose initial assumption of office occurs as a

result of any actual or threatened Election Contest that is subject to the provisions of Rule 14a-11 of the General Rules and

Regulations under the Exchange Act;

(c) the Company shall consummate a reorganization, merger, or consolidation, in each case, unless, following such

reorganization, merger, or consolidation, (i) 50% or more of the then outstanding shares of common stock of the corporation, or

common equity securities of an entity other than a corporation, resulting from such reorganization, merger, or consolidation and

the combined voting power of the then outstanding Voting Stock of such corporation or other entity are beneficially owned,

directly or indirectly, by all or substantially all of the Persons who were the Beneficial Owners of the outstanding Common

Stock immediately prior to such reorganization, merger, or consolidation in substantially the same proportions as their ownership,

immediately prior to such reorganization, merger, or consolidation, of the outstanding Common Stock, (ii) no Person (excluding

any Exempt Person or any Person beneficially owning, immediately prior to such reorganization, merger, or consolidation,

directly or indirectly, 20% or more of the Common Stock then outstanding or 20% or more of the combined voting power of the

Voting Stock of the Company then outstanding) beneficially owns, directly or indirectly, 20% or more of the then outstanding

shares of common stock of the corporation, or common equity securities of an entity other than a corporation, resulting from

such reorganization, merger, or consolidation or the combined voting power of the then outstanding Voting Stock of such

corporation or other entity, and (iii) at least a majority of the members of the board of directors of the corporation, or the body

which is most analogous to the board of directors of a corporation if not a corporation, resulting from such reorganization, merger,

or consolidation were members of the Incumbent Board at the time of the initial agreement or initial action by the Board providing

for such reorganization, merger, or consolidation; or

(d) (i) the shareholders of the Company shall approve a complete liquidation or dissolution of the Company unless such

liquidation or dissolution is approved as part of a plan of liquidation and dissolution involving a sale or disposition of all or

substantially all of the assets of the Company to a corporation with respect to which, following such sale or other disposition, all of

the requirements of clauses (ii)(A), (B), and (C) of this subsection (d) are satisfied, or (ii) the Company shall consummate the sale

or other disposition of all or substantially all of the assets of the Company, other than to a corporation or other entity, with respect

to which, following such sale or other disposition,

Effective 2/5/2013 Page 10 of 13 
(A) 50% or more of the then outstanding shares of common stock of such corporation, or common equity securities of an entity

other than a corporation, and the combined voting power of the Voting Stock of such corporation or other entity is then

beneficially owned, directly or indirectly, by all or substantially all of the Persons who were the Beneficial Owners of the

outstanding Common Stock immediately prior to such sale or other disposition in substantially the same proportion as their

ownership, immediately prior to such sale or other disposition, of the outstanding Common Stock, (B) no Person (excluding any

Exempt Person and any Person beneficially owning, immediately prior to such sale or other disposition, directly or indirectly, 20%

or more of the Common Stock then outstanding or 20% or more of the combined voting power of the Voting Stock of the

Company then outstanding) beneficially owns, directly or indirectly, 20% or more of the then outstanding shares of common

stock of such corporation, or common equity securities of an entity other than a corporation, and the combined voting power of

the then outstanding Voting Stock of such corporation or other entity, and (C) at least a majority of the members of the board of

directors of such corporation, or the body which is most analogous to the board of directors of a corporation if not a corporation,

were members of the Incumbent Board at the time of the initial agreement or initial action of the Board providing for such sale or

other disposition of assets of the Company.

Common Stock shall have the meaning set forth in the foregoing Plan.

Company shall have the meaning set forth in the foregoing Plan.

Election Contest shall mean a solicitation of proxies of the kind described in Rule 14a-12(c) under the Exchange Act.

Exchange Act shall mean the Securities Exchange Act of 1934, as amended.

Exempt Person shall mean any of the Company, any subsidiary of the Company, any employee benefit plan of the

Company or any subsidiary of the Company, and any Person organized, appointed or established by the Company for or pursuant to the

terms of any such plan.

Exempt Rights shall mean any rights to purchase shares of Common Stock or other Voting Stock of the Company if at the

time of the issuance thereof such rights are not separable from such Common Stock or other Voting Stock ( i.e., are not transferable

otherwise than in connection with a transfer of the underlying Common Stock or other Voting Stock), except upon the occurrence of a

contingency, whether such rights exist as of May 11, 2011 or are thereafter issued by the Company as a dividend on shares of Common

Stock or other Voting Securities or otherwise.

Exempt Transaction shall mean an increase in the percentage of the outstanding shares of Common Stock or the

percentage of the combined voting power of the outstanding Voting Stock of the Company beneficially owned by any Person solely as a

result of a reduction in the number of shares of Common Stock then outstanding due to the repurchase of Common Stock or Voting

Stock by the Company, unless and until such time as (a) such Person or any Affiliate or Associate of such Person shall purchase or

otherwise become the Beneficial Owner of additional shares of Common Stock constituting 1% or more of the then outstanding shares

of Common Stock or additional Voting Stock representing 1% or more of the combined voting power of the then outstanding Voting

Stock, or (b) any other Person (or Persons) who is (or collectively are) the Beneficial Owner of shares of Common Stock constituting

1% or more of the then outstanding shares of Common Stock or Voting Stock representing 1% or more of the combined voting power of

the then outstanding Voting Stock shall become an Affiliate or Associate of such Person.

Person shall mean any individual, firm, corporation, partnership, association, trust, unincorporated organization or other

entity.

Effective 2/5/2013 Page 11 of 13 
Voting Stock shall mean, (1) with respect to a corporation, all securities of such corporation of any class or series that are

entitled to vote generally in the election of, or to appoint by contract, directors of such corporation (excluding any class or series that

would be entitled so to vote by reason of the occurrence of any contingency, so long as such contingency has not occurred) and (ii) with

respect to an entity which is not a corporation, all securities of any class or series that are entitled to vote generally in the election of, or

to appoint by contract, members of the body which is most analogous to the board of directors of a corporation.

Effective 2/5/2013 Page 12 of 13 
Attachment B

2013 Restricted Stock Unit Early Vesting Schedule for Layoff & Retirement

Termination Date

 US/UK and Global Grant Payout %

 Retirement Layoff

Less than 6 months 0% 0%

Aug 5-Aug 31, 2013 100% 50%

Sep-2013 100% 58%

Oct-2013 100% 67%

Nov-2013 100% 75%

Dec-2013 100% 83%

Jan 1-Feb 4, 2014 100% 92%

Feb 5-Feb 28, 2014 100% 100%

Mar 2014 - Feb 2016 100% 100%

* For purposes of this table, Termination Date is the first day a participant is no longer employed by and performing services for ConocoPhillips or its subsidiaries.

Effective 2/5/2013 Page 13 of 13 
Exhibit 10.26.9

STOCK OPTION PROGRAM

FEBRUARY 5, 2013

KEY EMPLOYEE AWARD

TERMS AND CONDITIONS

This Key Employee Award Terms and Conditions describes terms and conditions of Stock Option (or Stock Appreciation Rights)

Awards, as part of the ConocoPhillips Stock Option Program (Program), granted under the 2011 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips (referred to as the Plan) by ConocoPhillips (Company) to certain eligible Employees (Employees).

These Terms and Conditions, together with the Annual Award Summary given to each Employee receiving an Award, form the Award

Agreement (the Agreement) relating to the Awards described. The Agreement covers both Stock Options and Stock Appreciation

Rights, and the term Employee covers recipients of Awards made either in Stock Options or Stock Appreciation Rights.

1. Type and Size of Grant. Subject to the Plan and this Agreement, the Company grants to certain eligible Employees a

Nonqualified Stock Option to purchase all or any part of an aggregate number of shares of Common Stock of the Company. In

certain countries, grants will be in the form of Stock Appreciation Rights (SARs). Individual awards will be as set forth in the

Annual Award Summary given to each Employee to whom an Award is granted. The Annual Award Summary for each

Employee is made a part of this Agreement with regard to such Employee.

2. Grant Date, Price, and Plan. The grant date is February 5, 2013 and the Grant Price is set forth on the Award Summary

given to each Employee to whom an Award is granted. Awards are made under the 2011 Omnibus Stock and Performance

Incentive Plan.

3. Term of Awards, Exercise Installments, and Last Date to Exercise. Except as otherwise noted in this Agreement, the

following summary table describes term of awards, exercise installments, and last date to exercise, subject to the more detailed

provisions set forth below:

Effective 2/5/2013 - 1 - 
Summary Table

Summary of Exercise Rules

Status Condition Last Date to Exercise

Active Employee 10 years from grant date

Retirement (age 55 and 5 years of service) 

Prior to 6 months

from grant date 

Canceled upon Termination

 

6 months from

grant date & after 

10 years from grant date

Layoff

 

Prior to 6 months

from grant date 

Canceled upon Termination

 

6 months to 1 year

from grant date 

10 years from grant date (award is prorated)

 

1 year from grant

date & after 

10 years from grant date

Disability

 

Any date after grant

date 

10 years from grant date

Death

 

Any date after grant

date 

10 years from grant date

Divestitures, outsourcing, and moves to joint ventures

 

Any date after grant

date 

Canceled upon Termination, unless approval otherwise

All other Terminations Canceled upon Termination

(a) Exercise Installments and Expiration. Stock Options/SAR’s granted under this Agreement will become exercisable to the

extent that one third of the number of shares of Stock subject to the Stock Option/SAR (rounded down to nearest whole

share) shall be exercisable on the first anniversary date of the Stock Option/SAR grant. On the second anniversary date of

the Stock Option/SAR grant, an additional one third of the number of shares of Stock (rounded down to nearest whole

share) shall become exercisable. On the third anniversary date of the Stock Option/SAR grant, the remaining shares shall

become exercisable. To the extent that an installment is not exercised when it becomes first exercisable, it will remain

exercisable at any time thereafter until the Award shall be canceled, expire, or be surrendered. A Stock Option or SAR

expires on the tenth anniversary of the date on which it was granted.

(b) Last Date to Exercise (Terminations).

(i) General Rule for Termination. If, prior to the exercise of Stock Options/SAR grants, the Optionee’s employment

with a Participating Company shall be terminated for any reason except death, Disability, Retirement, or Layoff,

such Award shall be canceled and all rights thereunder shall cease; provided that the Authorized Party may, in its or

his sole discretion, determine that all or any portion of any other Award shall not be canceled due to Termination of

Employment.

Effective 2/5/2013 - 2 - 
(ii) Layoff Within Six Months. If, prior to a date six months from the date an Award is granted, the Optionee’s

employment with a Participating Company shall be terminated by reason of Layoff, such Award shall be canceled

and all rights thereunder shall cease.

(iii) Layoff After Six Months but Within One Year. If, on or after a date six months from the date an Award is granted

but prior to a date one year from the date an Award is granted, the Optionee’s employment with a Participating

Company shall be terminated by reason of Layoff, the Optionee shall retain a prorated number of the Award shares

granted. The number of Award shares retained will be computed by multiplying the original number of Award

shares granted by a fraction, the numerator of which is the number of full months of employment from the first

day of the month in which the Award was granted until the date the employee is terminated and the denominator of

which is 12. Such calculation shall be rounded down to the nearest whole share.

(iv) Layoff After One Year. If, on or after a date one year from the date an Award is granted, the Optionee’s

employment with a Participating Company shall be terminated by reason of Layoff, the Optionee shall retain all

rights provided by the Award at the time of such Termination of Employment.

(v) Retirement After Six Months. If, on or after a date six months from the Grant Date of an Award, the Optionee’s

employment with a Participating Company shall be terminated by reason of Retirement, the Optionee shall retain all

rights provided by the Award at the time of such Termination of Employment.

(vi) Disability. If, after the date the Award is granted, an Optionee shall terminate employment following Disability of

the Optionee, the Optionee shall retain all rights provided by the Award at the time of such Termination of

Employment.

(vii) Death. If, after the date an Award is granted, an Optionee shall die while in the employ of a Participating Company ,

or after Termination of Employment by reason of Retirement, Disability, or Layoff (and prior to the cancellation of

the Award), the executor or administrator of the estate of the Optionee or the person or persons to whom the Award

shall have been validly transferred by the executor or the administrator pursuant to will or the laws of descent and

distribution shall have the right to exercise the Award to the same extent the Optionee could have, had the Optionee

not died. No transfer of an Award by the Optionee by will or by the laws of descent and distribution shall be

effective to bind the Company unless the Company shall have been furnished with written notice thereof and a

copy of the will and such other evidence as the Company may deem necessary to establish the validity of the

transfer and the acceptance by the transferee or transferees of the terms and conditions of such Award.

(viii) Transfers and Leaves. Transfer of employment between Participating Companies shall not constitute Termination

of Employment for the purpose of any Award granted under the Program. Whether any leave of absence shall

constitute Termination of Employment for the purposes of any Award granted under the Program shall be

determined in each case in accordance with applicable law and by application of the policies and procedures adopted

by the Company in relation to such leave of absence.

(ix) Divestiture, Outsourcing, or Move to Joint Venture. If, after the date the Award is granted, an Optionee ceases to

be employed by a Participating Company as a result of (a) the outsourcing of a function, (b) the sale or transfer of all

or a portion of the equity

Effective 2/5/2013 - 3 - 
interest of such Participating Company (removing it from the controlled group of companies of which the Company

is a part), (c) the sale of all or substantially all of the assets of such Participating Company to another employer

outside of the controlled group of corporations (whether the Optionee is offered employment or accepts

employment with the other employer), (d) the Termination of the Optionee by Participating Company followed by

employment within a reasonable time with a company or other entity in which the Company owns, directly or

indirectly, at least a 50% interest, prior to exercise of an Award, or (e) any other sale of assets determined by the

Authorized Party to be considered a divestiture under this program, the Authorized Party may, in its or his sole

discretion, determine that all or a portion of any such Award shall not be canceled.

(c) Detrimental Activities and Suspension of Exercises.

(i) If the Authorized Party determines that, subsequent to the grant of any Award, the Employee has engaged or is

engaging in any activity which, in the sole judgment of the Authorized Party, is or may be detrimental to the

Company or a subsidiary, the Authorized Party may suspend the right of the Employee to exercise, refuse to honor

the exercise of such Employee’s Awards already requested, or cancel all or part of the Award or Awards granted to

that Employee.

(ii) If the Authorized Party, in its or his sole discretion, determines that the exercise of any Award has the possibility of

violating any law, regulation, or decree pertaining to the Company, a subsidiary, or the Employee, the Authorized

Party may freeze or suspend the Employee’s right to exercise until such time as the exercise of the Award would no

longer, in the sole discretion of the Authorized Party, have the possibility of violating such law, regulation, or decree.

(iii) Notwithstanding anything herein to the contrary, any Award is subject to forfeiture or recoupment, in whole or in

part, under applicable law, including the Sarbanes-Oxley Act and the Dodd-Frank Act.

4. Exercising the Stock Option. The Company has retained outside firms to administer Stock Options (and SARs) granted under

the Plans (the “third party administrators”). The Option (or SAR) must be exercised in accordance with methods and at times set

by the third party administrator and by the Employee’s delivering to the third party administrators such authorization as may be

required.

5. Payment for Shares. The Grant Price for all shares of Stock purchased upon the exercise of a Stock Option, or a portion

thereof, shall be paid in full at the time of such exercise. Such payment may be made in cash or by tendering shares of Stock

having a value on the date of exercise equal to the Grant Price. Such value shall be the average of the high and low trading prices

of the stock on the day of exercise. If the Optionee makes payment of the Grant Price by tendering shares of Stock, such Stock

must be registered in the sole name of the Optionee on the exercise date or an appropriate Stock Power acceptable to the Company

to transfer such stock to the sole name of the Optionee must be provided at the time of exercise. In the case of an Optionee who

makes payment of the Grant Price by tendering shares of Stock, if the Company deems it appropriate, and if allowed by the

applicable laws, regulations and rulings, the Company may accept an attestation from the Optionee in lieu of actual physical

delivery to the Company of the shares to be tendered. The attestation must indicate the number of shares held, and if deemed

necessary by the Company, the certificate numbers if the Stock is held in certificate form, or the broker and brokerage account

number if the shares are held in a brokerage account, and any other information necessary to confirm ownership of the shares.

The Company may not accept an attestation in lieu of physical delivery of the shares unless the shares are

Effective 2/5/2013 - 4 - 
held in the sole name of the Optionee either in certificate form, or in a single brokerage account, or in such other form as the

Company may deem appropriate. Depending on its source, Stock tendered in the exercise of a Stock Option must have met the

appropriate holding period required by current tax, accounting, legal, or other applicable rules and regulations. At the election of

the Optionee (but subject to any administrative limitations on exercise of Stock Options or permissible methods of option exercise

imposed), the Stock Option may also be exercised by a “net-share settlement” method for exercising outstanding nonqualified

stock options. The Committee, in its sole discretion and judgment, limit the extent to which shares of Stock may be used in

exercising Stock Options or limit the use of any method or time of option exercise.

6. Assignment of Option and Exercises After Death . Rights under the Plans and this Agreement cannot be assigned or

transferred other than by (i) will, (ii) beneficiary designation, or (iii) the laws of descent and distribution. In the event that a

beneficiary designation conflicts with an assignment by will or under the laws of descent and distribution, the beneficiary

designation will prevail. Upon the death of an Employee, exercise of the grant will be permitted only by the Employee’s

designated beneficiary, executor, or personal representative of the Employee’s estate.

7. Tax Withholding. In the U.S. and many countries, the difference between the Grant Price and the value of the stock at the time

of an Option exercise multiplied by the number of shares purchased is compensation subject to tax withholding. The Option

exercise will not be completed until all federal, state, local and other governmental withholding tax requirements have been met.

Should a withholding tax obligation arise upon the exercise of a Stock Option, the withholding tax may be satisfied by withholding

shares of Stock or by payment of cash. This withholding obligation includes, but is not limited to, federal, state, and local taxes,

including applicable non-U.S. taxes, such as U.K. PAYE. The plan administrator will take such steps, as it deems necessary or

desirable for the withholding of any taxes that are required by laws or regulations of any governmental authority in connection

with any exercise. For SARs, the SAR Gain will be paid through the local payroll and is subject to applicable withholding taxes.

8. Shareholder Rights. The Employee shall not have the rights of a shareholder until the Option has been exercised and

ownership of shares of Common Stock has been transferred to the Employee. SARs never convey shareholder rights.

9. Certain Adjustments. In the event certain corporate transactions, recapitalizations, or stock splits occur while a Stock Option

(or SAR) is outstanding, the Grant Price and the number of Stock Option Shares (or SARs) shall be correspondingly adjusted.

10. Relationship to the Plan. In addition to the terms and conditions described in this Agreement, Awards are subject to all other

applicable provisions of the Plan. The decisions of the Committee with respect to questions arising as to the interpretation of the

Plan or this Agreement and as to findings of fact shall be final, conclusive, and binding.

11. No Employment Guarantee. No provision of this Agreement shall confer any right upon the Employee to continued

employment with any Participating Company.

12. Governing Law. This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of

Delaware.

13. Amendment. Without the consent of the Employee, this Agreement may be amended or supplemented (i) to cure any

ambiguity or to correct or supplement any provision herein which may be defective or inconsistent with any other provision

herein, or (ii) to add to the covenants and

Effective 2/5/2013 - 5 - 
agreements of the Company for the benefit of an Employee or to add to the rights of an Employee or to surrender any right or

power reserved to or conferred upon the Company in this Agreement, provided, in each case, that such changes or corrections

shall not adversely affect the rights of the Employee with respect to the grant of an Option (or SAR) evidenced hereby without

the Employee’s consent, or (iii) to make such other changes as the Company, upon advice of counsel, determines are necessary

or advisable because of the adoption or promulgation of, or change in or of the interpretation of, any law or governmental rule or

regulation, including any applicable federal or state securities or tax laws.

Effective 2/5/2013 - 6 - 
DEFINITIONS

Capitalized terms not defined below shall have the meanings set forth in the Plan under which the Award is granted.

“Authorized Party” means the person who is authorized to approve an Award, exercise discretion or take action under the

Administrative Procedure for the Stock Option (and Stock Appreciation Rights) Program and pursuant to the Program. With regard to

Senior Officers, the Committee is the Authorized Party. With regard to other Employees, the Chief Executive Officer, acting as the

Special Equity Award Committee of the Board of Directors of the Company, is the Authorized Party, although the Committee may act

concurrently as the Authorized Party.

“Award” means any Stock Option or SAR granted to an Employee pursuant to such applicable terms, conditions, and limitations as the

Authorized Party may establish in order to fulfill the objectives of the Program.

“Change of Control” has the meaning set forth in Attachment A to these Terms and Conditions.

“Committee” means the Human Resources and Compensation Committee of the Board of Directors of the Company, or any successor

committee to it.

“Common Stock” means common stock, par value $.01 per share, of the Company.

“Company” means ConocoPhillips a Delaware corporation.

“Disability” means a disability for which the employee in question has been determined to be entitled to either (i) benefits under the

applicable plan of long-term disability of the Company or its subsidiaries or (ii) disability benefits under the Social Security Act. In the

absence of any such determination, the Authorized Party may make a determination that the employee has a Disability.

“Fair Market Value” means, as of a particular date, the mean between the highest and lowest sales price per share of such Common

Stock on the consolidated transaction reporting system for the principal national securities exchange on which shares of Common Stock

are listed on that date, or, if there shall have been no such sale so reported on that date, on the next succeeding date on which such a sale

was so reported, or, at the discretion of the Committee, the price prevailing on the exchange at the time of exercise.

“Grant Price” means the price at which an Employee may exercise his or her right to receive cash or Common Stock, as applicable,

under the terms of an Award.

“Layoff” means an applicable Termination of Employment due to layoff under the ConocoPhillips Severance Pay Plan, the

ConocoPhillips Executive Severance Plan, or the ConocoPhillips Key Employee Change in Control Severance Plan, or layoff or

redundancy under any similar layoff or redundancy plan which the Company or its subsidiaries may adopt from time to time. If all or any

portion of the benefits under the redundancy or layoff plan are contingent on the employee’s signing a general release of liability, such

Termination shall not be considered as a “Layoff” for purposes of this Award unless the employee executes and does not revoke a

general release of liability, acceptable to the Company, under the terms of such layoff or redundancy plan.

“Nonqualified Stock Option” means a Stock Option that is not an Incentive Stock Option.

Effective 2/5/2013 - 7 - 
“Optionee” means an individual holding a Stock Option or SAR.

“Option Shares” means the shares of Common Stock issuable upon exercise of a Stock Option covered by this Agreement.

“Participating Company” includes ConocoPhillips and its 100% owned subsidiaries, including both those directly owned and those

owned through subsidiaries, whose participation has been approved by the Authorized Party.

“Retirement” means Termination at age 55 or older with a minimum of 5 years service with a Participating Company; provided,

however, that with regard to an Employee not on the United States payroll, the CEO may approve the use of a different definition.

Service is defined by the policies of the Participating Company.

“Senior Officer” means the Chairman of the Board, the CEO, all other executive officers of the Company (determined in accordance

with the Company’s custom and practice pursuant to section 16(b) of the Securities Exchange Act of 1934, as amended), all other

employees of the Company who report directly to the CEO and whose salary grade is 23 or higher, and all other employees of the

Company whose salary grade is 26 or higher.

“Stock” means shares of common stock of the Company, par value $.01.

“Stock Appreciation Right (SAR)” means a right to receive a payment, in cash equal to the excess of the Fair Market Value or other

specified valuation of a specified number of shares of Common Stock on the date the right is exercised over a specified Grant Price, in

each case, as determined by the Authorized Party.

“Stock Option” means the right to purchase a specified number of shares of Common Stock at a specified Grant Price pursuant to such

applicable terms, conditions, and limitations established by the Authorized Party.

“SAR Gain” means the difference between the Grant Price and the Fair Market Value (or other specified valuation) of a share of

Common Stock at the time of an SAR exercise, multiplied by the number of shares that are exercised.

“Termination” and “Termination of Employment” mean cessation of employment with the Participating Companies, determined in

accordance with the policies and practices of the Participating Company for whom the Employee was last performing services.

Effective 2/5/2013 - 8 - 
Attachment “A”

“Change of Control”

The following definitions apply to the Change of Control provision in Paragraph 10 of the Plan.

“Affiliate” shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under

the Exchange Act, as in effect at the time of determination.

“Associate” shall mean, with reference to any Person, (a) any corporation, firm, partnership, association,

unincorporated organization or other entity (other than the Company or a subsidiary of the Company) of which such Person is an officer

or general partner (or officer or general partner of a general partner) or is, directly or indirectly, the Beneficial Owner of 10% or more

of any class of equity securities, (b) any trust or other estate in which such Person has a substantial beneficial interest or as to which such

Person serves as trustee or in a similar fiduciary capacity and (c) any relative or spouse of such Person, or any relative of such spouse,

who has the same home as such Person.

“Beneficial Owner” shall mean, with reference to any securities, any Person if:

(a) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, is the “beneficial owner” of

(as determined pursuant to Rule 13d-3 of the General Rules and Regulations under the Exchange Act, as in effect at the

time of determination) such securities or otherwise has the right to vote or dispose of such securities;

(b) such Person or any of such Person’s Affiliates and Associates, directly or indirectly, has the right or obligation to

acquire such securities (whether such right or obligation is exercisable or effective immediately or only after the passage of

time or the occurrence of an event) pursuant to any agreement, arrangement or understanding (whether or not in writing)

or upon the exercise of conversion rights, exchange rights, other rights, warrants or options, or otherwise; provided,

however, that a Person shall not be deemed the Beneficial Owner of, or to “beneficially own,” (i) securities tendered

pursuant to a tender or exchange offer made by such Person or any of such Person’s Affiliates or Associates until such

tendered securities are accepted for purchase or exchange or (ii) securities issuable upon exercise of Exempt Rights; or

(c) such Person or any of such Person’s Affiliates or Associates (i) has any agreement, arrangement or

understanding (whether or not in writing) with any other Person (or any Affiliate or Associate thereof) that beneficially

owns such securities for the purpose of acquiring, holding, voting (except as set forth in the proviso to subsection (a) of this

definition) or disposing of such securities or (ii) is a member of a group (as that term is used in Rule 13d-5(b) of the

General Rules and Regulations under the Exchange Act) that includes any other Person that beneficially owns such

securities;

provided, however, that nothing in this definition shall cause a Person engaged in business as an underwriter of securities to be the

Beneficial Owner of, or to “beneficially own,” any securities acquired through such Person’s participation in good faith in a firm

commitment underwriting until the expiration of 40 days after the date of such acquisition. For purposes hereof, “voting” a security shall

include voting, granting a proxy, consenting or making a request or demand relating to corporate action (including, without limitation, a

demand for a shareholder list, to call a shareholder meeting or to inspect corporate books and records) or otherwise giving an

authorization (within the meaning of Section 14(a) of the Exchange Act) in respect of such security.

Effective 2/5/2013 - 9 - 
The terms “beneficially own” and “beneficially owning” shall have meanings that are correlative to this definition

of the term “Beneficial Owner.”

“Board” shall have the meaning set forth in the foregoing Plan.

“Change of Control” shall mean any of the following occurring on or after May 11, 2011:

(a) any Person (other than an Exempt Person) shall become the Beneficial Owner of 20% or more of the shares of

Common Stock then outstanding or 20% or more of the combined voting power of the Voting Stock of the Company then

outstanding; provided, however, that no Change of Control shall be deemed to occur for purposes of this subsection (a) if

such Person shall become a Beneficial Owner of 20% or more of the shares of Common Stock or 20% or more of the

combined voting power of the Voting Stock of the Company solely as a result of (i) an Exempt Transaction or (ii) an

acquisition by a Person pursuant to a reorganization, merger or consolidation, if, following such reorganization, merger or

consolidation, the conditions described in clauses (i), (ii) and (iii) of subsection (c) of this definition are satisfied;

(b) individuals who, as of May 11, 2011, constitute the Board (the “Incumbent Board”) cease for any reason to

constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to

May 11, 2011 whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at

least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a

member of the Incumbent Board; provided, further, that there shall be excluded, for this purpose, any such individual

whose initial assumption of office occurs as a result of any actual or threatened Election Contest that is subject to the

provisions of Rule 14a-11 of the General Rules and Regulations under the Exchange Act;

(c) the Company shall consummate a reorganization, merger, or consolidation, in each case, unless, following such

reorganization, merger, or consolidation, (i) 50% or more of the then outstanding shares of common stock of the

corporation, or common equity securities of an entity other than a corporation, resulting from such reorganization, merger,

or consolidation and the combined voting power of the then outstanding Voting Stock of such corporation or other entity are

beneficially owned, directly or indirectly, by all or substantially all of the Persons who were the Beneficial Owners of the

outstanding Common Stock immediately prior to such reorganization, merger, or consolidation in substantially the same

proportions as their ownership, immediately prior to such reorganization, merger, or consolidation, of the outstanding

Common Stock, (ii) no Person (excluding any Exempt Person or any Person beneficially owning, immediately prior to

such reorganization, merger, or consolidation, directly or indirectly, 20% or more of the Common Stock then outstanding

or 20% or more of the combined voting power of the Voting Stock of the Company then outstanding) beneficially owns,

directly or indirectly, 20% or more of the then outstanding shares of common stock of the corporation, or common equity

securities of an entity other than a corporation, resulting from such reorganization, merger, or consolidation or the

combined voting power of the then outstanding Voting Stock of such corporation or other entity, and (iii) at least a majority

of the members of the board of directors of the corporation, or the body which is most analogous to the board of directors of

a corporation if not a corporation, resulting from such reorganization, merger, or consolidation were members of the

Incumbent Board at the time of the initial agreement or initial action by the Board providing for such reorganization,

merger, or consolidation; or

(d) (i) the shareholders of the Company shall approve a complete liquidation or dissolution of the Company unless

such liquidation or dissolution is approved as part of a plan of

Effective 2/5/2013 - 10 - 
liquidation and dissolution involving a sale or disposition of all or substantially all of the assets of the Company to a

corporation with respect to which, following such sale or other disposition, all of the requirements of clauses (ii)(A), (B),

and (C) of this subsection (d) are satisfied, or (ii) the Company shall consummate the sale or other disposition of all or

substantially all of the assets of the Company, other than to a corporation or other entity, with respect to which, following

such sale or other disposition, (A) 50% or more of the then outstanding shares of common stock of such corporation, or

common equity securities of an entity other than a corporation, and the combined voting power of the Voting Stock of such

corporation or other entity is then beneficially owned, directly or indirectly, by all or substantially all of the Persons who

were the Beneficial Owners of the outstanding Common Stock immediately prior to such sale or other disposition in

substantially the same proportion as their ownership, immediately prior to such sale or other disposition, of the outstanding

Common Stock, (B) no Person (excluding any Exempt Person and any Person beneficially owning, immediately prior to

such sale or other disposition, directly or indirectly, 20% or more of the Common Stock then outstanding or 20% or more

of the combined voting power of the Voting Stock of the Company then outstanding) beneficially owns, directly or

indirectly, 20% or more of the then outstanding shares of common stock of such corporation, or common equity securities

of an entity other than a corporation, and the combined voting power of the then outstanding Voting Stock of such

corporation or other entity, and (C) at least a majority of the members of the board of directors of such corporation, or the

body which is most analogous to the board of directors of a corporation if not a corporation, were members of the

Incumbent Board at the time of the initial agreement or initial action of the Board providing for such sale or other

disposition of assets of the Company.

“Common Stock” shall have the meaning set forth in the foregoing Plan.

“Company” shall have the meaning set forth in the foregoing Plan.

“Election Contest” shall mean a solicitation of proxies of the kind described in Rule 14a-12(c) under the Exchange

Act.

“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.

“Exempt Person” shall mean any of the Company, any subsidiary of the Company, any employee benefit plan of

the Company or any subsidiary of the Company, and any Person organized, appointed, or established by the Company for or pursuant to

the terms of any such plan.

“Exempt Rights” shall mean any rights to purchase shares of Common Stock or other Voting Stock of the

Company if at the time of the issuance thereof such rights are not separable from such Common Stock or other Voting Stock ( i.e., are

not transferable otherwise than in connection with a transfer of the underlying Common Stock or other Voting Stock), except upon the

occurrence of a contingency, whether such rights exist as of May 11, 2011 or are thereafter issued by the Company as a dividend on

shares of Common Stock or other Voting Securities or otherwise.

“Exempt Transaction” shall mean an increase in the percentage of the outstanding shares of Common Stock or the

percentage of the combined voting power of the outstanding Voting Stock of the Company beneficially owned by any Person solely as a

result of a reduction in the number of shares of Common Stock then outstanding due to the repurchase of Common Stock or Voting

Stock by the Company, unless and until such time as (a) such Person or any Affiliate or Associate of such Person shall purchase or

otherwise become the Beneficial Owner of additional shares of Common Stock constituting 1% or more of the then outstanding shares

of Common Stock or additional Voting Stock representing 1% or more of the combined voting power of the then outstanding Voting

Stock, or (b) any other Person (or

Effective 2/5/2013 - 11 - 
Persons) who is (or collectively are) the Beneficial Owner of shares of Common Stock constituting 1% or more of the then outstanding

shares of Common Stock or Voting Stock representing 1% or more of the combined voting power of the then outstanding Voting Stock

shall become an Affiliate or Associate of such Person.

“Person” shall mean any individual, firm, corporation, partnership, association, trust, unincorporated organization, or

other entity.

“Voting Stock” shall mean, (1) with respect to a corporation, all securities of such corporation of any class or series

that are entitled to vote generally in the election of, or to appoint by contract, directors of such corporation (excluding any class or series

that would be entitled so to vote by reason of the occurrence of any contingency, so long as such contingency has not occurred) and

(ii) with respect to an entity which is not a corporation, all securities of any class or series that are entitled to vote generally in the

election of, or to appoint by contract, members of the body which is most analogous to the board of directors of a corporation.

Effective 2/5/2013 - 12 - 
Exhibit 12

CONOCOPHILLIPS AND CONSOLIDATED SUBSIDIARIES

TOTAL ENTERPRISE

Computation of Ratio of Earnings to Fixed Charges

 Millions of Dollars

 Years Ended December 31

 2012 2011 2010 2009 2008**

Earnings Available for Fixed Charges 

Income from continuing operations before income taxes and

noncontrolling interests that have not incurred fixed charges 

 $ 15,356 15,334 17,821 8,349 (7,967) 

Distributions less than equity in earnings of affiliates (596) (131) (357) (691) (2,259) 

Fixed charges, excluding capitalized interest* 1,127 1,160 1,440 1,540 1,126 

 $ 15,887 16,363 18,904 9,198 (9,100) 

Fixed Charges 

Interest and expense on indebtedness, excluding capitalized interest $ 749 972 1,187 1,289 935 

Capitalized interest 615 489 471 487 568 

Interest portion of rental expense 67 53 52 45 45 

Interest expense relating to guaranteed debt of affiliates - - - - 3 

 $ 1,431 1,514 1,710 1,821 1,551 

Ratio of Earnings to Fixed Charges 11.1 10.8 11.1 5.1 (5.9) 

* Includes amortization of capitalized interest totaling approximately $311 million in 2012, $135 million in 2011, $201 million in 2010, $206 million in 2009 and $143 million in

2008.

**For the year ended December 31, 2008, earnings were deficient by $10,651 million, which was due primarily to two pre-tax, non-cash charges of $25.4 billion related to an

impairment of goodwill and $7.4 billion related to the write-down in the carrying value of an equity investment.
Exhibit 21

SUBSIDIARY LISTING OF CONOCOPHILLIPS

Listed below are subsidiaries of the registrant at December 31, 2012. Certain subsidiaries are omitted since such companies considered in the aggregate do not

constitute a significant subsidiary.

Company Name 

Incorporation

Location

Ashford Energy Capital S.A. Luxembourg

BR (Global) Holdings B.V. Netherlands

BROG LP LLC Delaware

Burlington Resources (Irish Sea) Limited England

Burlington Resources (Netherlands) B.V. Netherlands

Burlington Resources (UK) Holdings Limited England

Burlington Resources Canada (Hunter) Ltd. Alberta

Burlington Resources China Holdings Limited Bermuda

Burlington Resources China LLC Delaware

Burlington Resources Finance Company Nova Scotia

Burlington Resources Inc. Delaware

Burlington Resources International Holdings LLC Delaware

Burlington Resources International Inc. Delaware

Burlington Resources Offshore Inc. Delaware

Burlington Resources Oil & Gas Company LP Delaware

Burlington Resources Trading LLC Delaware

Canadian Hunter Resources Alberta

Conoco Funding Company Nova Scotia

Conoco Orinoco Inc. Delaware

ConocoPhillips (03-12) Pty Ltd Victoria

ConocoPhillips (Browse Basin) Pty Ltd Western Australia

ConocoPhillips (Grissik) Ltd. Bermuda

ConocoPhillips (U.K.) Eta Limited England

ConocoPhillips (U.K.) Limited England

ConocoPhillips (U.K.) Sigma Limited England

ConocoPhillips (U.K.) Theta Limited England

ConocoPhillips (U.K.) Zeta Limited England

ConocoPhillips Alaska, Inc. Delaware

ConocoPhillips Algeria Ltd. Cayman Islands

ConocoPhillips ANS Marketing Company Delaware

ConocoPhillips Asia Ventures Pte. Ltd. Singapore

ConocoPhillips Australia Gas Holdings Pty Ltd Western Australia

ConocoPhillips Australia Holdings Pty Ltd Australia

ConocoPhillips Australia Pacific LNG Pty Ltd Western Australia

ConocoPhillips Australia Pty Ltd Western Australia

ConocoPhillips Bohai Limited Bahamas

ConocoPhillips Canada (BRC) Partnership Alberta

ConocoPhillips Canada (North) Limited Canada

ConocoPhillips Canada Energy Partnership Alberta

1
Company Name 

Incorporation

Location

ConocoPhillips Canada Marketing & Trading ULC Alberta

ConocoPhillips Canada Resources Corp. Alberta

ConocoPhillips China Inc. Liberia

ConocoPhillips Funding Ltd. Bermuda

ConocoPhillips Golden Pass Holdings LLC Delaware

ConocoPhillips Gulf of Paria B.V. Netherlands

ConocoPhillips Hamaca B.V. Netherlands

ConocoPhillips Holdings Limited England

ConocoPhillips Indonesia Holding Ltd. British Virgin Islands

ConocoPhillips Indonesia Inc. Ltd. Bermuda

ConocoPhillips Libya Waha Ltd. Cayman Islands

ConocoPhillips N Block B.V. Netherlands

ConocoPhillips NGL Marketing (Canada) ULC Alberta

ConocoPhillips Norge Delaware

ConocoPhillips North Caspian Ltd. Liberia

ConocoPhillips Petroleum Company U.K. Limited England

ConocoPhillips Petroleum Holdings B.V. Netherlands

ConocoPhillips Petrozuata B.V. Netherlands

ConocoPhillips Pipeline Australia Pty Ltd Western Australia

ConocoPhillips Qatar Funding Ltd. Cayman Islands

ConocoPhillips Qatar Ltd. Cayman Islands

ConocoPhillips Russia Inc. Delaware

ConocoPhillips Sabah Gas Ltd. Cayman Islands

ConocoPhillips Sabah Ltd. Bermuda

ConocoPhillips Skandinavia AS Norway

ConocoPhillips Surmont Partnership Alberta

ConocoPhillips Transportation Alaska, Inc. Delaware

ConocoPhillips WA-248 Pty Ltd Western Australia

ConocoPhillips Western Canada Partnership Alberta

Continental Oil Company (Nederland) B.V. Netherlands

COP Holdings Limited England

Darwin LNG Pty Ltd Western Australia

Dubai Petroleum Company Delaware

Inexco Oil Company Delaware

Phillips Coal Company Nevada

Phillips International Investments, Inc. Delaware

Phillips Investment Company LLC Nevada

Phillips Oil Company Nigeria Ltd. Nigeria

Phillips Petroleum International Corporation LLC Delaware

Phillips Petroleum International Investment Company LLC Delaware

Phillips-San Juan Partners, L.P. Delaware

Polar Tankers, Inc. Delaware

Sooner Insurance Company Vermont

The Louisiana Land and Exploration Company LLC Maryland

2
Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference of our reports dated February 19, 2013, with respect to the consolidated financial statements, condensed

consolidating financial information, and financial statement schedule of ConocoPhillips, and the effectiveness of internal control over financial reporting of

ConocoPhillips, included in this Annual Report (Form 10-K) for the year ended December 31, 2012, in the following registration statements and related

prospectuses.

ConocoPhillips Form S-3  File No. 333-179626

ConocoPhillips Form S-4  File No. 333-130967

ConocoPhillips Form S-8  File No. 333-98681

ConocoPhillips Form S-8  File No. 333-116216

ConocoPhillips Form S-8  File No. 333-133101

ConocoPhillips Form S-8  File No. 333-159318

ConocoPhillips Form S-8  File No. 333-171047

ConocoPhillips Form S-8  File No. 333-174479

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2013
Exhibit 23.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 19, 2013

ConocoPhillips

600 North Dairy Ashford

Houston, Texas 77079

Ladies and Gentlemen:

We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton as an independent petroleum

engineering consulting firm under “Part II” under the heading “Item 8. Financial Statements and Supplementary Data,” under the subheading “Reserves

Governance” and under “Part IV” under the heading “Item 15. Exhibits, Financial Statement Schedules” under the subheading “Index to Exhibits” in

ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2012, and to the inclusion of our process review letter report dated

February 19, 2013, (our Report) as an exhibit to ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2012. We also consent to the

incorporation by reference of our Report in the Registration Statements filed by ConocoPhillips on Form S-3 (No. 333-179626), Form S-4 (No. 333-130967)

and Form S-8 (No. 333-98681, No. 333-116216, No. 333-133101, No. 333-159318, No. 333-171047, and No. 333-174479).

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716
Exhibit 31.1

CERTIFICATION

I, Ryan M. Lance, certify that:

1. I have reviewed this annual report on Form 10-K of ConocoPhillips;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the

statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the

financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))

for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to

ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those

entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our

supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for

external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent

fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to

materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably

likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control

over financial reporting.

February 19, 2013

/s/ Ryan M. Lance

Ryan M. Lance

Chairman and

Chief Executive Officer
Exhibit 31.2

CERTIFICATION

I, Jeff W. Sheets, certify that:

1. I have reviewed this annual report on Form 10-K of ConocoPhillips;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the

statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this

report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects

the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us

by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under

our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial

statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most

recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably

likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are

reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal

control over financial reporting.

February 19, 2013

/s/ Jeff W. Sheets

Jeff W. Sheets

Executive Vice President, Finance and

Chief Financial Officer
Exhibit 32

CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Annual Report of ConocoPhillips (the Company) on Form 10-K for the period ended December 31, 2012, as filed with the U.S.

Securities and Exchange Commission on the date hereof (the Report), each of the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as

adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to their knowledge:

(1) The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 19, 2013

/s/ Ryan M. Lance

Ryan M. Lance

Chairman and

Chief Executive Officer

/s/ Jeff W. Sheets

Jeff W. Sheets

Executive Vice President, Finance and

Chief Financial Officer
Exhibit 99

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 19, 2013

ConocoPhillips

600 North Dairy Ashford

Houston, Texas 77079

Re: SEC Process Review

Ladies and Gentlemen:

Pursuant to your request, DeGolyer and MacNaughton has performed a process review of the processes and controls used within ConocoPhillips in

preparing its internal estimates of proved reserves, as of December 31, 2012. The process review, which is contemplated by Item 1202 (a) (8) of Regulation SK of the Securities and Exchange Commission (SEC), has been performed specifically to address the adequacy and effectiveness of ConocoPhillips’ internal

processes and controls relative to its estimation of proved reserves in compliance with Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC.

DeGolyer and MacNaughton has participated as an independent member of the internal ConocoPhillips Reserves Compliance Assessment Team in

reviews and discussions with each of the relevant ConocoPhillips business units relative to SEC proved reserves estimation. DeGolyer and MacNaughton

participated in the review of all major fields in all countries where ConocoPhillips has proved reserves worldwide, which ConocoPhillips has indicated

represents over 90 percent of its estimated total proved reserves as of December 31, 2012.

The reviews with ConocoPhillips’ technical staff involved presentations and discussions of a) basic reservoir data including seismic data, well log

data, pressure and production tests, core analysis, pressure-volume-temperature data, and production history, b) technical methods employed in SEC proved

reserves estimation, including performance analysis, geology, mapping, and volumetric estimates, c) economic analysis, and d) commercial assessment,

including the legal basis for the interest in the reserves, primarily related to lease agreements and other petroleum license agreements, such as concession and

production sharing agreements.

A field examination of the properties was not considered necessary for the purposes of this review of ConocoPhillips’ processes and controls.
Exhibit 99

DeGolyer and MacNaughton

It is our opinion that ConocoPhillips’ estimates of proved reserves for the properties reviewed were prepared by the use of recognized geological and

engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered

by ConocoPhillips’ experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. It is our opinion

that the general processes and controls employed by ConocoPhillips in estimating its December 31, 2012, proved reserves for the properties reviewed are in

accordance with the SEC reserves definitions.

This process review of ConocoPhillips’ procedures and methods does not constitute a review, study, or independent audit of ConocoPhillips’

estimated proved reserves and corresponding future net revenues. This report is not intended to indicate that DeGolyer and MacNaughton is offering any

opinion as to the reasonableness of reserves estimates reported by ConocoPhillips.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services

throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in ConocoPhillips. Our fees

were not contingent on the results of our evaluation.

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Thomas C. Pence, P.E.

Thomas C. Pence, P.E.

Senior Vice President

DeGolyer and MacNaughton