Howard Weil Energy Conference March 2014

Forward Looking Statement Cautionary Statement This presentation contains forward-looking statements in which Freeport-McMoRan Oil & Gas (FM O&G) discusses its potential future performance. Forward-looking statements are all statements other than statements of historical facts, such as projections or expectations relating to production, reserve estimates, cash production costs per barrel of oil equivalent (BOE), operating cash flows, cash margin and cash flow estimates, capital expenditures, exploration efforts and results, development and production activities and costs, the impact of crude oil and natural gas price changes, and the impact of derivative positions. The words “anticipates,” “may,” “can,” “plans,” “believes,” “estimates,” “expects,” “projects,” “intends,” “likely,” “will,” “should,” “to be,” and any similar expressions are intended to identify those assertions as forward-looking statements. FM O&G cautions readers that forward-looking statements are not guarantees of future performance or exploration and development success, and its actual exploration experience and future financial results may differ materially from those anticipated, projected or assumed in the forward-looking statements. Important factors that can cause FM O&G’s actual results to differ materially from those anticipated in the forward-looking statements include variations in the market demand for, and prices of, crude oil and natural gas, drilling results and production rates, changes in oil and gas reserve expectations, unanticipated hazards for which we have limited or no insurance coverage, adverse conditions, such as high temperatures and pressure that could lead to mechanical failures or increased costs, the ability to retain current or future lease acreage rights, industry risks, regulatory changes, political risks, weather- and climate-related risks, environmental risks, as well as other general oil and gas exploration and development risks and hazards, and other factors described in more detail under the heading “Risk Factors” in Freeport-McMoRan Copper & Gold Inc.’s (FCX) Annual Report on Form 10-K for the year ended December 31, 2013, filed with the U.S. Securities and Exchange Commission (SEC), as updated by FCX’s subsequent filings with the SEC. Investors are cautioned that many of the assumptions on which FM O&G’s forward-looking statements are based are likely to change after its forward-looking statements are made, including for example the market prices of crude oil and natural gas, which FM O&G cannot control, and production volumes and costs, some aspects of which FM O&G may or may not be able to control. Further, FM O&G may make changes to its business plans that could or will affect its results. FM O&G cautions investors that it does not intend to update forward-looking statements more frequently than quarterly notwithstanding any changes in FM O&G’s assumptions, changes in business plans, actual experience or other changes, and FM O&G undertakes no obligation to update any forward-looking statements. The SEC requires companies with significant oil and gas producing activities to disclose, in their filings with the SEC, proved oil and gas reserves that has been demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC also permits the disclosure of probable and possible oil and gas reserves, as such terms are defined by the SEC. FM O&G uses certain phrases and terms in this presentation, such as "net resource potential” which the SEC's guidelines prohibit FCX from including in its filings with the SEC. “Net resource potential” does not take into account the certainty of resource recovery, which is contingent on exploration success, technical improvements in drilling access, commerciality and other factors, and is therefore not indicative of expected future resource recovery and should not be relied upon. This presentation contains certain financial measures such as cash operating margin, which is commonly used in the oil and gas industry but not recognized under U.S. Generally Accepted Accounting Principles. As required by SEC Regulation G, reconciliations of this measure to amounts reported in FCX’s consolidated financial statements are included in the Addendum to this presentation.

2

Brent Historical Prices / Forward Curves Worldwide Oil Demand

$/b

bl

30,000

30,500

31,000

31,500

32,000

32,500

33,000

33,500

34,000

34,500

35,000

Dem

an

d in

mm

bb

ls

WW Oil Demand

Brent Price

3 Source: Brent Historical Prices & Forward Curves - Goldman Sachs, NYMEX, ICE; Worldwide Oil Demand – FM O&G, EIA.

Oil & Gas Portfolio

4

Madden

Haynesville

Gulf of Mexico

San Joaquin Valley

Arroyo Grande

Santa Maria Basin

Los Angeles Basin

Eagle Ford

California • 434 MMBOE total resource potential

• 188 MMBOE proved reserves

• 2,000+ future locations

• Brent based pricing

Eagle Ford • 144 MMBOE total resource potential

• 59 MMBOE proved reserves

• 300+ future locations

• LLS pricing

Gulf of Mexico • 6.6 Billion BOE total resource potential

• 171 MMBOE proved reserves

• 175+ future locations

• HLS pricing

Madden • 133 BCFE total resource potential

• 107 BCFE proved reserves

• 30+ future locations

• NYMEX pricing

Haynesville • 4.7 TCFE total resource potential

• 158 BCFE proved reserves

• 11,000+ future locations

• NYMEX pricing

Morocco • 3.3 Billion BOE total resource

potential

• Brent pricing

Morocco

Algeria GALP

Genel

Genel

Kosmos, BP

Chevron

FM O&G

Cairn

Cairn, Genel

Mazagan Permit Area

Agadir

Chariot

Africa

Chevron

Kosmos, BP

Kosmos, BP

Note: SEC end of year 2013 proved reserves. Total resource potential includes unrisked proved, probable, possible, development and exploration.

Year End 2013 3P Reserves

5

464

184

213

0

250

500

750

1000

2013

MM

BO

E

Proved Probable Possible

861

Note: The 3P oil and gas reserves presented were determined using the methods prescribed by the U.S. Securities and Exchange Commission, which require the use of an average price, calculated as the twelve-month historical average of the first-day-of-the-month West Texas Intermediate spot oil price of $96.94 per barrel and Henry Hub spot natural gas price of $3.67 per million British thermal units, as adjusted for location and quality differentials by area, and were held constant throughout the lives of the properties unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

2013 3P Reserves

6

By Region By Commodity

6:1 Ratio

861 MMBOE as of 12/31/13

Oil

76%

Gas

20%

4%

California

41%

GOM

43%

Eagle

Ford

9%

7%

NGLs

Note: Please refer to note on slide 5.

Haynesville/ Other

Strong Operating Performance

- 40% Increase in pro forma production volumes compared to prior year

- 125% Increase in pro forma cash flow compared to prior year

Advanced Important Projects for Profitable Future Growth

- Lucius deepwater GOM Development nearing first production in 2H 2014

- Holstein platform rig activated and commenced drilling operations

- New growth opportunities in deepwater GOM identified

- Inboard Lower Tertiary/Cretaceous Opportunity on GOM Shelf and Onshore South Louisiana

- Highlander discovery announced

- Record oil production from the Eagle Ford Shale with reduced rig count

2013 Year in Review Focused on Execution

7

A Strong & Focused Organization

8

Key Strengths

Strong Management of the Base Production

- Offshore GOM (2)

- California

˗ Eagle Ford

Effective Capital Management

- Focus on oil & gas cash operating margins

- Manage production/investment to maximize cash flow

Return Driven Growth

- Concentrate on high return projects including offshore redevelopment from existing infrastructure and development drilling onshore

- Exploration focused on high impact projects to drive future returns

2013 MBOE/D

72

39

46

2013 Cash Operating Margins(1)

$70

$62

$67

(1) Cash operating margin reflects revenues (excluding derivatives) less cash production costs for the 7 months ended December 31, 2013. Refer to slide 33 of the addendum. (2) Includes properties on the Shelf and in the Deepwater GOM.

Operational Plan

9

$2,500 $3,000$3,500

$4,000 $4,100 $4,400 $4,500 $4,700

$0

$800

$1,600

$2,400

$3,200

$4,000

$4,800

$5,600

$6,400

$7,200

0

50

100

150

200

250

300

350

400

450

PF2013 2014E 2015E 2016E 2017E 2018E 2019E 2020E

MB

OE

/D

Net Production

MM

$

Oil & Gas Cash Operating Margin

(1)(2)

CAPEX

Cash Operating Margin Plan(2) Production Cash Operating Margin 2013 Actual(3)

(1) Oil and Gas revenues less cash production costs. (2) Assumes $105.00/Bbl Brent based oil pricing in 2014 and $100.00/Bbl in 2015 and beyond and natural gas pricing of $3.50/MMBtu in 2014 and $4.50/MMBtu in

2015 and beyond. (3) Actual prices of $108.66/Bbl Brent and $3.67/MMBtu natural gas.

2013 Results Significantly

Exceeded Plan

Los Angeles

Basin

San Joaquin Valley

Arroyo Grande

Pt Pedernales

Pt Arguello

Base Oil Producing Assets

10

California

38,900 BOE/D 4Q 2013 Production

2,000+ Future Locations

Brent Based Pricing

Eagle Ford

48,200 BOE/D 4Q 2013 Production

300+ Future Locations

LLS Pricing

Gulf of Mexico

72,800 BOE/D 4Q 2013 Production

HLS Pricing

Texas Louisiana

WILSON

ATASCOSA

KARNES

Per BOE Cash Operating Margin Strength by Area 4Q 2013

Cash Production Costs $12

Cash Production Costs $35

Cash Production Costs $11

Deepwater GOM California Eagle Ford

Cash Operating Margin

$64

Cash Operating Margin

$75

Cash Operating Margin

$54

Note: Cash production costs include lease operating expenses, production and ad valorem taxes, steam gas costs, and gathering and transportation expenses. Cash operating margin reflects revenues (excluding derivatives) less cash production costs. Refer to slide 34 of the addendum. 11

Cash Operating Margin Leader Quarter Ending December 31, 2013

FM O&G

Note: Sources: public filings, Barclays. Companies referenced in this chart: Apache, Anadarko, Chesapeake, Chevron, ConocoPhillips,

Devon, EOG, Exxon, Marathon and Occidental.

Cash operating margin per BOE, a non-GAAP measure, is defined and reconciled to the most comparable GAAP measure, gross

profit, included in the Addendum. FM O&G does not make any representations as to the accuracy of the information used to make

the calculations on the conformity of this measure with those that may be presented by the respective companies, and does not

undertake to provide GAAP reconciliation with respect to any non-GAAP financial measure that may be included in such

information. Refer to slide 34 of the addendum.

12

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$/BOE

Dynamic Production Growth

13

0

50

100

150

200

250

300

350

2014 2015 2016 2017 2018 2019 2020

Operating Development Exploration

Green Canyon Area Inboard Lower

Tertiary/Cretaceous

Inboard Lower Tertiary/Cretaceous

Keathley Canyon Lower Tertiary Mississippi

Canyon Area Green Canyon Area Keathley Canyon

Pliocene-Miocene

MB

OE/

D

Keathley Canyon Pliocene-Miocene Mississippi

Canyon Area Inboard Lower Tertiary/Cretaceous

Exploration/Development Growth Areas

14

Louisiana

Garden Banks

Keathley Canyon

Walker Ridge Lund

Atwater Valley

Mississippi Canyon

Viosca

Knoll

Mississippi Canyon Area

Green Canyon

2

3

1

4

Green Canyon Area

Inboard Lower Tertiary/Cretaceous

Keathley Canyon Pliocene-Miocene

5

Morocco

Africa

Morocco

Drilling activities to date have successfully confirmed geologic model and have indicated the potential for a major new geologic trend spanning 200 miles in the shallow waters of the GOM and onshore in the Gulf Coast area.

Conceptual Model Inboard Lower Tertiary/Cretaceous

15

Recognized as Industry Leader in This New Exploration Frontier

Texas Louisiana

Lineham Creek

Exploration

Development Assets

Inboard Lower Tertiary/ Cretaceous

England Davy Jones

Blackbeard Area

Highlander

Approximately 15 identified exploration and development projects

Spud dates starting May 2014 with net resource potential for the initial program of 2.5 Billion BOE

The Highlander discovery well is currently in completion operations to test Lower Wilcox and Cretaceous objectives found below the salt weld. The Lineham Creek discovery well located in Cameron Parish was drilled to 24,600 feet and has been suspended while future plans are being developed. Completion operations are also underway at Davy Jones #2 well located on South Marsh Island Block 234, and in addition we plan to complete the Blackbeard West #2 well located on Ship Shoal Block 188 in 2014

1

16

Highlander Discovery – Cretaceous Tuscaloosa

17

Gross Pay

Economics: 20 – 30% ROR $0.5 - $1.0 B Net PV10% $5/mcf - $6/mcf

Highlander Discovery FM O&G

Jeanerette Minerals #1

LOUISIANA

Tuscaloosa Trend Cumulative Production 3.1 TCF, 121 mmbc

Cretaceous Tuscaloosa Discoveries

Highlander

Davy Jones

Cretaceous Tuscaloosa

Trend

3.0 TCF Gross Resource Potential

Proposed Location

Highlander Discovery

Highlander Discovery – Cretaceous Tuscaloosa

18 Gross Pay

Judge Digby Field Type Log

Highlander Discovery FM O&G

Jeanerette Minerals #1

Tusc 2

Tusc 3

Tusc 1

Proposed Location

Highlander Discovery LOUISIANA

Tuscaloosa Trend Cumulative Production 3.1 TCF, 121 mmbc

Cretaceous Tuscaloosa Discoveries

Highlander

Davy Jones

Cretaceous Tuscaloosa

Trend

3.0 TCF Gross Resource Potential

East Breaks

Alaminos Canyon

Garden Banks

Keathley Canyon Walker Ridge

Atwater Valley

Mississippi Canyon

Viosca Knoll

Texas Louisiana

Green Canyon

Discoveries

FM O&G Leases

Marlin

Horn Mountain

Holstein

Ram Powell

Hoover

Diana

Phobos

Lucius

Deepwater Gulf of Mexico

19

Deepwater Gulf of Mexico Exploration & Development

20

Production Area

Net Installed Oil

Production

Capacity

(BOE/D)

Capacity

Utilization

Net Leasehold

Acreage

Net Resource

Potential

(MMBOE)

Mississippi Canyon 68,000 286

Horn Mountain 75,000 12%

Marlin 60,000 45%

Green Canyon 58,000 995

Holstein 113,500 11%

Keathley Canyon 122,000 1,677

Lucius 19,000 Start up 2H 2014

Other Explor. & Dev. 201,000 861

Total 267,500 449,000 3,819 Note: Information above does not include the recent 2014 Central GOM Lease Sale.

2014 Central GOM Lease Sale

21

Area Blocks Net Acreage Facility

Shelf 4 14,224

Mississippi Canyon 9 51,840 Horn Mountain

Viosca Knoll 2 11,520 Marlin

Green Canyon 2 11,520 Holstein

Atwater Valley 3 17,280

Total 20 106,384

Total Net Resource Potential 1.1 Billion BOE

Total Bid $330 MM

Note: The Company expects to be notified and designated operator of these blocks by the third quarter of 2014.

VK0868 VK0869 VK0870 VK0871 VK0872 VK0873

VK0912 VK0913 VK0914 VK0915 VK0916 VK0916

VK0956 VK0957 VK0958 VK0959 VK0960 VK0961

VK1000 VK1001 VK1002 VK1003 VK1004 Vk1005

38 39 40 41 0001 0002

82 83 84 85 0045 0046

126 127 128 129 0089 0090

170 171 172 173 0133 0134

Mississippi Canyon Area

Dorado

8 MMBOE

King 112

MMBOE

Platinum 32 MMBOE

Horn Mountain

134 MMBOE

Exploration

Development Assets

Ram Powell

Marlin 19 identified exploration and

development projects targeting stacked, high quality Miocene reservoir sands

286 MMBOE net resource potential

Horn Mountain hub volumes expected to reach ~60 MBOE/D in 2H 2018

Marlin hub volumes expected to approach 60 MBOE/D by late 2018

22

2

23

King Field Composite Type Log

Mississippi Canyon King M63

Prop D3ST

M63 Sand Attic

Prop M63 #1

NW Fault Block

Prop M63 #1ST1

D3

M63 Sand Producer A

A’

Prop #3

Prop #2

Prop D9

80 MMBOE Net Resource Potential

24

Mississippi Canyon Horn Mountain Deep

126 127

MC 127 HM Deep OH

MC 127 HM Deep Up-dip S/T

Deeper pool test below proven J&M

Sand field pays targeting the M56 Sand

which has been found productive in

several nearby exploration prospects

Large structural closure with numerous

offset opportunities

Horn Mountain

Composite Type Log 47 MMBOE Net Resource Potential

598 599 600 601 602 603

642 643 644 645 646 647

686 687 688 689 690 691

730 731 732 733 734 735

818 819 820 821 822 823

862 863 864 865 866 867

Tungsten

Holstein

Holstein Deep

Copper 137 MMBOE

106 MMBOE

25 MMBOE 65

MMBOE

Green Canyon Area

25

Silver Fox

Exploration

Development Assets

94 MMBOE

14 identified exploration and development projects targeting highly productive Miocene and Wilcox sands

995 MMBOE net resource potential

Holstein hub volumes expected to reach 40 MBOE/D in 2H 2016

3

568 MMBOE

Green Canyon Holstein Deep Development Miocene Type Log

GC 643

OCS-G 16772 #1 & 1ST2

Proposed Wells

Oil

26

141.5 MMBOE Net Resource Potential

Keathley Canyon Area Pliocene Miocene

Lucius

Tara

Phobos

Diana

Hoover Keathley Canyon

East Breaks

Alaminos Canyon

Garden Banks

Sigsbee Escarpment Exploration

Development Assets

Non-Op Producing Assets

1 identified development project and 4 identified exploration projects targeting highly productive Pliocene and Miocene sands

Lucius, the development project, is currently in completion

Spud dates for the 4 identified exploration projects starting April 2014

1.7 Billion BOE net resource potential

4

27

Lucius Spar Installation

28

• 300+ MMBOE gross resource

• World-class reservoir quality and deliverability

• First oil in second-half 2014

Lucius 1

Lucius 2

Lucius 3

919 Lucius 5

Lucius 6

Planned Producer Gas Oil

Keathley Canyon Lucius Development

29

Lucius 4 Miocene

Completion Miocene

Pliocene

82 MMBOE Net Resource Potential

Morocco Miocene and Cretaceous Exploration

Approximately 8 identified exploration projects

Spud dates starting January 2015

Net resource potential of 1.7 Billion BOE for the first 3 prospects (Toubkal, Jbel Musa and Amtoudi)

5

30

Freeport-McMoRan Oil & Gas Today

31

High Value Production With Superior Margins

+ High Impact Development Projects Directed Around

Producing Assets

+ Emerging Exploration From Inboard Lower

Tertiary/Cretaceous, International and Deepwater Gulf of Mexico

= High Growth Oil Production with

Industry Leading Margins

Addendum

32

33

Reconciliation of Cash Operating Margin (Non-GAAP) to Gross Profit (GAAP)

The following table reconciles cash operating margin, a non-GAAP measure, to gross profit (GAAP) for the seven months ended December 31, 2013. Management believes this presentation may be useful to investors. FM O&G management uses this information for comparative purposes within the industry and as a means to measure operating performance by our oil and gas production and the ability to fund, among other things, capital expenditures and acquisitions. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating FM O&G’s operational trends and performances. Cash operating margin for our oil and gas operations reflects realized revenues less cash production costs. Realized revenues exclude net unrealized and noncash realized losses on derivative contracts and cash production costs exclude accretion and other costs.

Seven Months Ended December 31, 2013

(In Millions)

Total

Oil & Gas

Oil and gas revenues before derivatives $ 2,949

Realized losses on derivative contracts (22)

Realized revenues 2,927

Less: cash production costs 653

Cash operating margin 2,274

Less: depreciation, depletion and amortization 1,364

Less: accretion and other costs 29

Plus: net unrealized and noncash realized losses on derivative contracts (312)

Plus: other net adjustments 1

Gross profit $ 570

Per BOE

Oil and gas revenues before derivatives $ 77.45

Realized losses on derivative contracts (0.58)

Realized revenues 76.87

Less: cash production costs 17.14

Cash operating margin 59.73

Less: depreciation, depletion and amortization 35.81

Less: accretion and other costs 0.79

Plus: net unrealized and noncash realized losses on derivative contracts (8.20)

Plus: other net adjustments 0.04

Gross profit $ 14.97

MMBOE

Revenues

(in millions)

Average Realized Price

per BOE

Cash Production

Costs

(in millions)

Cash Production

Costs

per BOE

Deepwater and GOM Shelf 15.3 $ 1,284 $ 84.00 $ 213 $ 13.94

Eagle Ford 9.9 783 78.87 119 11.97

California 8.3 779 93.95 268 32.33

Haynesville/Madden/Other 4.6 103 22.47 53 11.46

38.1 $ 2,949 77.45 $ 653 17.14

34

Reconciliation of Cash Operating Margin (Non-GAAP) to Gross Profit (GAAP)

The following table reconciles cash operating margin, a non-GAAP measure, to gross profit (GAAP) for the three months ended December 31, 2013. Management believes this presentation may be useful to investors. FM O&G management uses this information for comparative purposes within the industry and as a means to measure operating performance by our oil and gas production and the ability to fund, among other things, capital expenditures and acquisitions. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating FM O&G’s operational trends and performances. Cash operating margin for our oil and gas operations reflects realized revenues less cash production costs. Realized revenues exclude net unrealized and noncash realized losses on derivative contracts and cash production costs exclude accretion and other costs.

Three Months Ended December 31, 2013

(In Millions)

Total

Oil & Gas

Oil and gas revenues before derivatives $ 1,233

Realized losses on derivative contracts (11)

Realized revenues 1,222

Less: cash production costs 293

Cash operating margin 929

Less: depreciation, depletion and amortization 632

Less: accretion and other costs 12

Plus: net unrealized and noncash realized losses on derivative contracts (118)

Plus: other net adjustments -

Gross profit $ 167

Per BOE

Oil and gas revenues before derivatives $ 74.27

Realized losses on derivative contracts (0.69)

Realized revenues 73.58

Less: cash production costs 17.63

Cash operating margin 55.95

Less: depreciation, depletion and amortization 38.06

Less: accretion and other costs 0.78

Plus: net unrealized and noncash realized losses on derivative contracts (7.12)

Plus: other net adjustments 0.04

Gross profit $ 10.03

MMBOE

Revenues

(in millions)

Average Realized Price

per BOE

Cash Production

Costs

(in millions)

Cash Production

Costs

per BOE

Deepwater GOM 5.6 $ 485 $ 86.61 $ 68 $ 12.14

Eagle Ford 4.4 333 75.05 51 11.42

California 3.6 318 88.96 124 34.87

Haynesville/Madden/GOM Shelf/Other 3.0 97 32.33 50 16.67

16.6 $ 1,233 74.27 $ 293 17.63