INVESTMENT Credit Suisse 19 th Annual Energy Summit Jeff Sheets, - - PowerPoint PPT Presentation

a new class of E&P

INVESTMENT

Credit Suisse 19th Annual Energy Summit Jeff Sheets, EVP, Finance & CFO

• Feb. 12, 2014

The following presentation includes forward-looking statements. These statements relate to future events, such as anticipated revenues, earnings, business strategies, competitive position or other aspects of our operations

• r operating results. Actual outcomes and results may differ materially

from what is expressed or forecast in such forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict such as oil and gas prices; operational hazards and drilling risks; potential failure to achieve, and potential delays in achieving expected reserves or production levels from existing and future oil and gas development projects; unsuccessful exploratory activities; unexpected cost increases or technical difficulties in constructing, maintaining or modifying company facilities; international monetary conditions and exchange controls; potential liability for remedial actions under existing or future environmental regulations or from pending or future litigation; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; general domestic and international economic and political conditions, as well as changes in tax, environmental and other laws applicable to ConocoPhillips’ business and other economic, business, competitive and/or regulatory factors affecting ConocoPhillips’ business generally as set forth in ConocoPhillips’ filings with the Securities and Exchange Commission (SEC). Use of non-GAAP financial information – This presentation includes non- GAAP financial measures, which are included to help facilitate comparison

• f company operating performance across periods and with peer
• companies. A reconciliation of these non-GAAP measures to the nearest

corresponding GAAP measure is included in the appendix. Cautionary Note to U.S. Investors – The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible

• reserves. We use the term "resource" in this presentation that the SEC’s

guidelines prohibit us from including in filings with the SEC. U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10-K and other reports and filings with the SEC. Copies are available from the SEC and from the ConocoPhillips website.

Cautionary Statement

ConocoPhillips: A New Class of E&P Investment

3

We offer the marketplace a new class of E&P investment. Our goal is to consistently deliver strong, predictable returns to shareholders.

Operational Financial Strategic

2013 Highlights

 $7.1 B adjusted

earnings, $5.70 adjusted EPS

 $15.8 B CFO; $6.5 B

ending cash2

 Visible cash margin

improvement

 Closed 2013

dispositions for proceeds of $10.2 B

 Increased dividend

by 4.5% in 3Q13

 Delivered strong

total shareholder returns

 Met production

target for the year; achieved 179%

• rganic RRR1

 Growth from major

project startups and development programs

 Three deepwater

successes in GOM

1RRR represents reserve replacement ratio. 2Cash from continuing operations (CFO) was $15.8 B; ending cash includes cash and cash equivalents of $6.2 B and short-term investments of $0.3 B.

4

ConocoPhillips: Unmatched as an Independent E&P Today

5

 Largest independent E&P

company

 Diverse asset base with scope

and scale

• Multiple sources of growth
• Positioned in key resource trends

globally

 Significant technical capability  Strong balance sheet  Commitment to shareholders

1 Production from continuing operations. 2 Preliminary proved reserves

Largest independent E&P based on production and proved reserves. Natural gas production and resources targeted toward liquefied natural gas depicted as LNG.

Liquids LNG + International Gas North American Gas OECD Non OECD Liquids LNG Gas

Production: 1,490 – 1,530 MBOED1 (1Q14e) Proved Reserves2: 8.9 BBOE (YE 2013) Resources: 43 BBOE (YE 2012)

57% 18% 25%

What Will We Deliver?

6

 Relentless focus on safety and

execution

 Compelling dividend  3 – 5% production growth rate  3 – 5% margin growth rate  Ongoing priority to improve

financial returns

Production and margin reflect compound annual growth rates.

A Compelling Dividend is Key to Our Value Proposition

7

 Highest priority use of cash flow  Enhances capital discipline  Predictable portion of shareholder

returns

 Differential compared to range of

peers

 4.5 percent increase in 3Q13;

targeting consistent increases

Peers include: APA, APC, BG, BP, CVX, DVN, OXY, RDS, TOT, XOM.

Independents Integrateds

Dividend Yield1

4.2%

Commitment to Capital Discipline and Growth

8

* Reflects production from 2012-2013 closed and announced dispositions.

• 0.2

0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2012 2013 2014 2015 2016 2017 Development Programs Major Projects Exploration & Appraisal Base Maintenance

45% 30% 15% 10%

Mitigates base decline Delivers 2017+ growth

Production – MMBOED Annual Capital ~$16 B

* Development Programs Major Projects Base Peak spend for named projects

• ccurs in

2014 Protects the base 2013-2017 Development Programs Major Projects Exploration & Appraisal Base Maintenance

 Five significant areas ramping up between 2012-2017  Incremental growth comes from high-margin investments  Lower-risk geographies and geologies; diversified plays

9

Our Commitment to Margin Improvement

1 Based on 2013 real prices of $100 Brent / $90 WTI / $70 WCS / $3.50 Henry Hub. Assumes partial sell down of APLNG and oil sands interests.

Oil Sands Lower 48 Liquids Rich APLNG Europe Malaysia Development Programs Major Projects

10

Operating segments only. Numbers have been adjusted for special items. A reconciliation is available in the appendix.

1 Price normalized using published sensitivities.

2013 Performance – Cash Margin Improvement

Growth In Higher-Margin Production

 Growth comes from areas with

higher margins than the company average

 Significant growth in North

American liquids

 Alaska and Europe liquids and

North American natural gas impacted by normal field decline

1 Continuing operations adjusted for dispositions, Libya and downtime. 2 Includes Europe and Other International natural gas.

11

2013 Reserve Replacement

 Year-end reserves of 8.9 BBOE

• Organic reserve replacement ratio of 179%
• Total reserve replacement ratio of 147%; asset

sales reduced reserves by 188 MMBOE

 Organic reserve additions of approximately

1.1 BBOE, primarily from:

• Eagle Ford and Bakken in the Lower 48
• Oil sands and western Canada
• APLNG

 Reserve additions approximately 75

percent from liquids-priced products

• Approximately 60 percent from liquids
• Approximately 15 percent from natural gas

reserve additions tied to liquids-pricing through LNG

Reserve Additions (MMBOE)1

1 Reserve additions are approximate numbers.

12

Alaska

Nabors 7ES at Kuparuk 4Q 2013 Highlights

 Applied for new LNG export license for

Kenai plant

 Construction ramping up for CD5  Projects progressing at Drill Site 2S and

Greater Moose's Tooth 1

Full-Year 2013 Highlights

 Successfully completed major

turnarounds at Kuparuk and Prudhoe

 New rig added at Kuparuk  Initiated additional development activity

after passage of MAPA

What to Watch in 2014

 Major turnaround expected at Prudhoe  Ongoing development activity at Kuparuk  Continuing major project activity on CD5,

Drill Site 2S and Greater Moose's Tooth 1

 Drilling 2 exploration wells in the NPR-A  Additional progress on AK LNG project

13

Lower 48 and Latin America

Bakken 4Q 2013 Highlights

 Winter weather impacted production  Achieved peak production rate of 141

MBOED in Eagle Ford; 43 MBOED in Bakken

 Discovery at Gila; ongoing appraisal at Tiber

and Coronado; exploration drilling at Deep Nansen

Full-Year 2013 Highlights

 Production up 7% year-over-year; 24%

increase in crude oil

 Major growth in unconventional plays  Continued to drill and test in Permian and

Niobrara with encouraging results

 Deepwater GOM success at Coronado,

Gila and Shenandoah

What to Watch in 2014

 Continuing growth in Eagle Ford and

Bakken

 Increasing unconventional activity in

Permian, Niobrara and Colombia

 Continuing exploration and appraisal in

deepwater GOM

14

Canada

Surmont 4Q 2013 Highlights

 Production at Christina Lake Phase E

ramping up

 Increased development activity in western

Canada

 Winter drilling program underway

Full-Year 2013 Highlights

 Production up 1% year-over-year; 13%

increase in liquids

 Strong performance at Christina Lake  Construction over 60% complete at

Surmont Phase 2

 Progress on drilling programs

What to Watch in 2014

 Continuing development drilling and

unconventional exploration activity in western Canada

 Foster Creek Phase F on track for first

production in 3Q14

 Progressing Surmont Phase 2 project with

first steam expected mid-2015

15

Europe

Jasmine 4Q 2013 Highlights

 Winter weather impacted North Sea

production

 Planned turnarounds completed at Clair  Spud Lublewo LEP-1 well in Poland  Ekofisk South and Jasmine first production

Full-Year 2013 Highlights

 Completed major turnarounds at Greater

Ekofisk, J-Area and Clair

 Continued progress on additional major

projects

 Awarded 4 licenses in the Barents Sea

What to Watch in 2014

 Ekofisk South, Jasmine and East Irish Sea

ramp up

 Startup expected at Britannia Long-Term

Compression in 3Q14; final preparations for Eldfisk II startup by early 2015

 Drilling in the Barents Sea and continuing

to appraise in Poland

16

Asia Pacific and Middle East

APLNG at Curtis Island 4Q 2013 Highlights

 Planned turnaround completed at

Qatargas 3

 Obtained operatorship and 100% WI in

Palangkaraya PSC in Indonesia

 Qijiang Block seismic acquisition

completed in China

Full-Year 2013 Highlights

 Progress SNP and Gumusut toward

startup

 Significant progress at APLNG reaching

~60% project completion

 Proteus-1 gas discovery in Browse Basin

What to Watch in 2014

 SNP and Gumusut first oil expected 1H14;

KBB on target for first gas in late 2014

 Progressing APLNG project with first LNG

expected mid-2015

 Continuing appraisal offshore Australia  Expect to begin drilling in Palangkaraya in

late 2014

17

Wolfcamp, Niobrara & Avalon Duvernay, Muskwa, Montney & Canol Poland Sichuan Canning Gulf of Mexico West Greenland Barents Sea & North Sea Azerbaijan Bangladesh Malaysia Angola Browse & Bonaparte Indonesia Colombia

Diverse Unconventional and Conventional Exploration Portfolio

Conventional Unconventional Senegal

18

Operational Financial Strategic

2014: Set for Growth

19

 Ongoing margin

improvement

 Focus on improving

financial returns

 Committed to

compelling dividend

 Focus on executing

• ur current plan

 Positioning for

long-term success

 Delivering on value

proposition

 Continued ramp up

• f unconventional

drilling programs

 Growth from major

projects

 Exploration

momentum continues

Our Value Proposition

20

 Relentless focus on safety and

execution

 Compelling dividend  3 – 5% production growth rate  3 – 5% margin growth rate  Ongoing priority to improve

financial returns

Production and margin reflect compound annual growth rates.

Supplemental Slides

Margin Improvement from Strong Growth and Mix Shift

 Investment strategy drives strong organic growth  Visible growth by end of 2013  High-margin growth creates ~$6 B of incremental cash flow

• $40-$45 per BOE average cash margin1
• Liquids growth from areas with lower tax rates

1 Based on 2013 real prices of $100 Brent / $90 WTI / $70 WCS / $3.50 Henry Hub. Assumes partial sell down of APLNG and oil sands interests.

22

~35 MBOED ~105 MBOED ~365 MBOED ~10 MBOED ~25 MBOED ~40 MBOED

Canada Lower 48 Other Int’l Asia Pacific Europe Alaska

High-Margin Worldwide Development Program Inventory

Development Program Growth (2012-2017) MBOED

23

 Development programs will account for ~600 MBOED by 2017  >60% of production growth from high-impact Lower 48 programs

23

Permian Conventional: Decades of Legacy Field Inventory

 5-year investment: ~$3 B  Incremental F&D: ~$15/BOE  ~1 MM net acres; 0.8 BBOE resource  Infill drilling and waterflood expansion  Adds ~40 MBOED by 2017  Results in ~7% CAGR through 2017

24

Permian Basin

Texas New Mexico COP Minerals COP Leasehold

Central Platform Basin

 5-year investment: ~$4 B  Incremental F&D: ~$20/BOE  626 M net acres1; 0.6 BBOE resource  >1,400 identified drilling locations  Top-quartile initial production rates2  Adds ~45 MBOED by 2017  Results in ~18% CAGR through 2017

Bakken: Growth from Development in Heart of Trend

1 207 M net lease acres and 419 M net mineral acres. 2 Source: IHS Enerdeq.

25

Bakken

COP Minerals COP Leasehold STARK

North Dakota Montana

WILLIAMS ROOSEVELT MCKENZIE RICHLAND DAWSON BILLINGS DUNN WARD MOUNTRAIL

Nesson Anticline

Eagle Ford: Nearing Full Field Development Phase

 5-year investment: ~$8 B  Incremental F&D: ~$20/BOE  227 M net acres; 1.8 BBOE resource  Highest-quality position in sweet spot, acquired

at $300/acre

 >1,800 identified drilling locations  Adds ~130 MBOED by 2017  Results in ~16% CAGR through 2017

16 26

Eagle Ford

BEXAR GUADALUPE GONZALES DE WITT WILSON ATASCOSA KARNES GOLIAD BEE LIVE OAK MCMULLEN Oil Window Condensate Dry Gas COP Leasehold

Unconventional Reservoirs: Technology Leadership

 Sweet spot identification  Development plan

• ptimization

 Efficient drilling and

completions

 Operations excellence

27

Proven ability to identify, secure and develop highest-value unconventional acreage

1 Source: Wood Mackenzie.

Unconventional Reservoirs: Sweet Spot Identification

 Multi-disciplinary approach  Eagle Ford, Bakken and Permian successful outcomes  Securing additional liquids-rich sweet spots

1 Source: 1Q13 gross 2-stream data from IHS for APC, BHP, CHK, COP, EOG, MRO and PXD.

Early mover in best parts of plays yields best-in-class results

28

Eagle Ford Competitors – Average Oil Rate per Well (BD)1

Total Production (BOED)

• Avg. Well

Count Total Production per Well (BOED) % Oil Oil Production per Well (BD) COP 118,000 350 337 69% 233 Competitor Average 117,000 473 247 62% 153 50 100 150 200 250 COP Competitor Average

~55 MBOED

United Kingdom

~75 MBOED1

APLNG

~60 MBOED

Norway

~70 MBOED

Malaysia

~55 MBOED

Other Major Projects

~100 MBOED1

Oil Sands

High-Margin Major Growth Projects in Execution

 Major projects will account for ~400 MBOED by 2017  Lower-risk geographies and geologies; diversified market exposure

Major Projects Growth (2012-2017) MBOED

29

1 Assumes partial sell down of APLNG and oil sands interests. Represents incremental production.

30

Oil Sands: Significant Growth from Projects in Execution

 5-year investment: ~$5 B1  Full-cycle F&D: ~$15/BOE  Surmont Phase 2 first steam in 2015  FCCL: Executing projects at Foster Creek,

Christina Lake and Narrows Lake

 Employing new technologies to improve

efficiency and cost of supply

 Total oil sands ~16% CAGR

Christina Lake

2017 Cash Margin – $/BOE2

1 Assumes partial sell down of oil sands interests. 2 Based on 2013 real prices of $100 Brent / $90 WTI / $70 WCS / $3.50 Henry Hub; equity affiliates shown on a proportionally consolidated basis.

United Kingdom: Strong Production Growth from Projects

 5-year investment: ~$2.5 B  Full-cycle F&D: ~$20/BOE  Jasmine: Largest recent discovery in U.K. sector;

started production in 4Q13

 High-value exploration opportunities can be

tested from Jasmine platform

 Additional projects include: Britannia satellite

developments and compression project, East Irish Sea developments and Clair Ridge

31

1 Based on 2013 real prices of $100 Brent / $90 WTI / $70 WCS / $3.50 Henry Hub.

2017 Cash Margin – $/BOE1

Jasmine

Norway: Major Projects Drive Another 40 Years of Production

 5-year investment: ~$4 B  Full-cycle F&D: ~$25/BOE  Ekofisk South and Eldfisk II will continue to improve oil recovery from the Greater Ekofisk Area  Additional projects include: Tor Redevelopment, Tommeliten Alpha and Aasta Hansteen

32

Ekofisk South

1 Based on 2013 real prices of $100 Brent / $90 WTI / $70 WCS / $3.50 Henry Hub.

Malaysia: Projects Ramping Up, with Upside

 5-year investment: ~$2.5 B  Full-cycle F&D: ~$15/BOE  4 developments in execution: Gumusut, SNP,

KBB and Malikai

 Gumusut full field and SNP first oil

expected 1H14

 Additional growth potential in Pisagan, Ubah,

Limbayong, KME discoveries and SB 311 exploration

1 Based on 2013 real prices of $100 Brent / $90 WTI / $70 WCS / $3.50 Henry Hub.

2017 Cash Margin – $/BOE1

Oil Field COP Acreage Gas Field

Malaysia

33

1 Assumes partial sell down. 2 Based on 2013 real prices of $100 Brent / $90 WTI / $70 WCS / $3.50 Henry Hub; equity affiliates shown on a proportionally consolidated basis.

 5-year investment: ~$2.5 B1  Full-cycle F&D: ~$25/BOE  Initial focus on two 4.5 MTPA LNG

trains

 Project on schedule for first cargo

mid-2015

 Permitted for two additional trains  Phase 1 capital ~7% increase on AUD

basis as of February 2013

APLNG: Project Progressing On Schedule

APLNG

2017 Cash Margin – $/BOE2 34

Wolfcamp, Niobrara & Avalon Duvernay, Muskwa, Montney & Canol Poland Sichuan Canning Gulf of Mexico West Greenland Barents Sea & North Sea Azerbaijan Bangladesh Malaysia Angola Browse & Bonaparte Indonesia Colombia

Diverse Unconventional and Conventional Exploration Portfolio

35

Conventional Unconventional Senegal

Focus area

UPTON REAGAN CROCKETT PECOS CRANE ECTOR MIDLAND GLASSCOCK WARD WINKLER ANDREWS MARTIN DAWSON HOWARD BORDEN GAINES LOVING LEA REEVES JEFF DAVIS CULBERSON EDDY

Texas New Mexico

COP Minerals COP Leasehold

Midland Basin Delaware Basin Central Platform Basin

Permian

Permian Unconventional: Emerging Growth

 Active exploration across Permian Basin that leverages existing ~1 MM net acre position  High-grading positions around and within core legacy producing area  Measured approach as infrastructure is developed  Encouraging results consistent with expectations

36

Delaware Basin: Wolfcamp Avalon Bone Spring

~150 M net acres

Midland Basin: Wolfcamp

89 M net acres

International Conventionals: Deepwater Angola

 Play identified as a probable analog to Brazil

pre-salt play

 Recent discoveries de-risk play concept in

Kwanza Basin

 ConocoPhillips-operated 2.5 MM acre position  2012-2013: 3-D seismic acquisition confirms

presence of multiple promising prospects

 2014: 4+ well drilling program begins

Brazil Angola

Oceanic Crust

West

Km

East

12 6 Marlim/ Jubarte Cameia Campos Fault Outer Ramp Outer Ramp Mid Atlantic Ridge Atlantic Hinge Blocks 36 & 37

Angola

37

COP Acreage

Exploration Catalysts in Deepwater GOM

38

 Three deepwater successes

announced

• Shenandoah appraisal well discovery

>1,000 feet net pay

• Coronado wildcat discovery >400 feet

net pay

• Gila wildcat discovery

 Successfully acquired additional

prospective acreage in central region in 2013

 Inventory building and drilling activity

continues

• Ongoing appraisal at Tiber and

Coronado; exploration drilling at Deep Nansen

• Preparing for 2014 operated drilling

program Deepwater GOM Net Acreage (MM)

0.0 0.5 1.0 1.5 2.0 2.5 2011 2012 20131

WI: 25% Target: L Tertiary Non Operated Deep Nansen WI: 18% Target: L Tertiary Non Operated Tiber Texas Louisiana WI: 30% Target: L Tertiary Non Operated Shenandoah WI: 35% Target: L Tertiary Non Operated Gila WI: 20% Target: L Tertiary Non Operated Appraisal Exploration ConocoPhillips Acreage Coronado

2013 Gulf of Mexico Exploration

1 As of June 2013.

Appendix

Annualized Net Income Sensitivities

 Crude

• Brent/ANS: $75-85 MM change for $1/BBL change
• WTI: $30-40 MM change for $1/BBL change
• WCS1: $20-25 MM change for $1/BBL change

 North American NGL

• Representative blend: $10-15 MM change for $1/BBL change

 Natural Gas

• HH: $115-125 MM change for $0.25/MCF change
• International gas: $10-15 MM change for $0.25/MCF change

40

1 WCS price used for the sensitivity should reflect a one-month lag.

* The published sensitivities above reflect annual estimates and may not apply to quarterly results due to lift timing/product sales differences, significant turnaround activity or other unforeseen portfolio shifts in production. Additionally, the above sensitivities apply to the current range of commodity price fluctuations, but may not apply to significant and unexpected increases or decreases.

Unconventional Reservoirs: Optimizing Full Field Development

 Rapid experimentation with disciplined science  Eagle Ford EUR growth more than 100% since 2010  Bakken EUR growth more than 50% since 2010  Pursuing a multitude of promising technologies

41

Downhole Distributed Temperature Sensors

200 400 600 800 1,000 1,200

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33

BOED Months on Production

Single change in completion design

Example: Eagle Ford Completion Design

Science-based experimentation to optimize unconventional recovery

Top-Tier Oil Sands Position with Massive Resource Base

 More than 1 MM net acres  Top-quartile average steam-to-oil

ratio

 Resource: ~16 BBOE  2nd largest steam-assisted gravity

drainage (SAGD) producer

 6 major project phases in execution

42

Project Schedule Competitive Resource

Cumulative Steam-to-Oil Ratio1

1 Source: First Energy Capital Corp. 2 Christina Lake Phase E first steam in July 2013.

2.0 2.3 2.7

1 2 3 4 5 6 7 8

Christina Lake Foster Creek Surmont

Industry Average ConocoPhillips Projects Other Oil Sands Projects

Oil Sands

2

Oil Sands: Unlocking the Value in Major Projects

43

 Advances based on modeling,

lab and field work

 Better returns with lower

emissions

• Fish hook and extension wells
• Flow control devices
• Solvent injection
• Vacuum insulated tubing

 Targeting $20+ per barrel

reduction in cost of supply

 Improved economics on

16 BBOE oil sands resource

Today's Developments Proven Technologies Technologies in Development Future Developments

$20 per barrel reduction in cost of supply

Example: Value Creation in Oil Sands

Extension Wells Fish Hook Infill Well

Cost of Supply

Game-changing technology to reduce oil sands cost of supply

International Conventionals: Offshore Senegal

 Farmed in to the Rufisque, Sangomar

and Sangomar Deep blocks in the Mauritania-Senegal-Guinea-Bissau Basin in July 2013

 Approximately 650,000 net acres  Acreage covered by 3-D seismic survey,

prospects identified

 Drilling expected to begin 1H14

Senegal

44

COP Acreage

Segment Production (MBOED)

* Reflects production from 2012-2013 closed and announced dispositions.

45

A Diverse Portfolio Delivering Production and Margin Growth

46

 Diverse, resource-rich global portfolio  High-quality legacy base  Profitable worldwide development programs  Major projects in execution  Compelling exploration opportunities  Positioned to deliver high-margin organic growth

and reserve replacement >100%

* Reflects production from 2012-2013 closed and announced dispositions.

4Q FY 3Q 4Q FY Consolidated Earnings 1,426 8,428 2,480 2,487 9,156 Adjustments: Impairments 351 901

• 269

269 Net (gain)/loss on asset sales

• (1,532)

(749)

• (1,075)

Bohai Bay incidents

• 89
• Tax loss carryforward realization

(236) (236)

• (1)

International tax law changes

• 167
• Deferred tax adjustment
• (72)
• FCCL IFRS depreciation adjustment
• (33)

(33) Separation costs 4 84

• Pension settlement expense

5 87 31 10 41 Pending claims and settlements (196) (235) 116

• (118)

Premium on early debt retirement

• 68
• Discontinued operations - Phillips 66

16 (1,232)

• Discontinued operations - Other

385 217 (57) (995) (1,178) Adjusted earnings 1,755 6,734 1,821 1,738 7,061 Earnings per share of common stock 1.16 6.72 2.00 2.00 7.38 Adjusted earnings per share of common stock 1.43 5.37 1.47 1.40 5.70 2013 2012

Non-GAAP Reconciliations

Reconciliation of Earnings to Adjusted Earnings

($ Millions) 47

Non-GAAP Reconciliations

Cash Margin per BOE Operating Segments Price Normalized Cash Margin per BOE 2 Operating Segments

assumptions regarding the impact of commodity price changes on earnings. The estimated annualized earnings sensitivities are based on the sensitivities published in our 2013 Analyst Meeting.

2012 2013 FY FY Cash Margin 14,328 15,650 Price adjustment (using published sensitivities)

• (305)

Price Normalized Cash Margin 14,328 15,345 Production from Continuing Operations (MBOED) 1,527 1,502 Price Normalized Cash Margin $ / BOE 25.64 27.99 2012 2013 FY FY $ Millions, except per BOE amounts Net Income Attributable to ConocoPhillips 8,428 9,156 Adjustment to exclude special items (1,694) (2,095) Adjusted Earnings 6,734 7,061 Exclude adjusted earnings for Corporate and Other 813 781 Depreciation, depletion & amortization 6,494 7,338 Impairments1 (23) 27 Dry holes and leasehold impairment1 310 443 Cash Margin 14,328 15,650 Production from Continuing Operations (MBOED) 1,527 1,502 Cash Margin $ / BOE 25.64 28.55

48

Abbreviations and Glossary

 3-D: three dimensional  ANS: Alaska North Slope  B: billion  Base Production: production from existing infrastructure  BBL: barrel  BBOE: billions of barrels of oil equivalent  BD: barrels of oil  BOE: barrels of oil equivalent  CAGR: compound annual growth rate  CFO: cash from operations  CSOR: cumulative steam-to-oil ratio  CTD: coiled tubing drilling  Development Programs: drilling and optimization activity  EUR: estimated ultimate recovery  F&D: finding and development  GAAP: generally accepted accounting principles  GOM: Gulf of Mexico  HBP: held by production  HH: Henry Hub  Liquid Yield: liquid-to-gas ratio  LNG: liquefied natural gas  M: thousand  MM: million  MBOED: thousands of barrels of oil equivalent per day  MMBOE: millions of barrels of oil equivalent  MMBOED: millions of barrels of oil equivalent per day  MTPA: millions of tonnes per annum  NOC: national oil company  OECD: Organisation for Economic Co-operation and Development  ROCE: return on capital employed  SAGD: steam-assisted gravity drainage  SDL: steerable drilling liner  TSR: total shareholder return  WCS: Western Canada Select  WI: working interest  WTI: West Texas Intermediate 49

Investor Information

 Stock Ticker:

NYSE: COP www.conocophillips.com/investor

 Headquarters:

ConocoPhillips 600 N. Dairy Ashford Road Houston, Texas 77079

 Investor Relations:

• Telephone: +1.212.207.1996
• Ellen DeSanctis: ellen.r.desanctis@conocophillips.com
• Sidney J. Bassett: sid.bassett@conocophillips.com
• Vladimir R. dela Cruz: v.r.delacruz@conocophillips.com
• Mary Ann Cacace: maryann.f.cacace@conocophillips.com

50

 New York IR Office:

ConocoPhillips 375 Park Avenue, Suite 3702 New York, New York 10152