Continental Resources Inc (CLR) 8-K Regulation FD Disclosure

Pr ivate

&

Conf idential

2007 E&P Conference

A.G. Edwards

July 18, 2007

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*

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Exhibit 99.1

1

Pr ivate

&

Conf idential

Forward Looking Statements

This

presentation

includes

forward-looking

information

that

are

subject

to

a

number

of

risks

and

uncertainties,

many

of

which

are

beyond

our

control.

All

information,

other

than

historical

facts

included

in

this

presentation,

regarding

our

strategy,

future

operations,

drilling

plans,

estimated

reserves,

future

production,

estimated

capital

expenditures,

projected

costs,

the

potential

of

drilling

prospects

and

other

plans

and

objectives

of

management

are

forward-looking

information.

All

forward-looking

statements

speak

only

as

of

the

date

of

this

presentation.

Although

the

Company

believes

that

the

plans,

intentions

and

expectations

reflected

in

or

suggested

by

the

forward-

looking

statements

are

reasonable,

there

is

no

assurance

that

these

plans,

intentions

or

expectations

will

be

achieved.

Actual

results

may

differ

materially

from

those

anticipated

due

to

many

factors,

including

oil

and

natural

gas

prices,

industry

conditions,

drilling

results,

uncertainties

in

estimating

reserves,

uncertainties

in

estimating

future

production

from

enhanced

recovery

operations,

availability

of

drilling

rigs

and

other

services,

availability

of

oil

and

natural

gas

transportation

capacity,

availability

of

capital

resources

and

other

factors

listed

in

reports

we

have

filed

or

may

file

with

the

Securities

and

Exchange

Commission.

2

Pr ivate

&

Conf idential

Company Overview

Completed IPO on May 14 at $15 (CLR on NYSE)

–

$2.9 billion market capitalization

Founded 1967 by Harold Hamm, Chairman & CEO

–

Harold Hamm, family and management own 82%

Organic growth strategy focused on unconventional resource plays

–

99% of proved reserve adds through drill bit over last 3 years

–

78% of proved reserves located in unconventional resources

–

>700,000 net undeveloped acres concentrated in emerging plays

Strong financial position

–

$150 million of bank debt outstanding

–

2007E cash flows to substantially fund $437mm capital budget

3

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Conf idential

$94

$145

$327

$437

2004

2005

2006

2007E

Investment in Asset Base

Capex ($mm)

14,121

19,751

24,707

27,911

2004

2005

2006

Q1 '07

Production (Boe/d)

$116

$285

2004

2005

2006

2007E

EBITDAX

1

($mm)

1

See page 9 of the prospectus and first quarter 2007 earnings release for a reconciliation of net income to EBITDAX.

2

Average of DB, JPM, ML and RJ equity analyst reports.

$372

Total = $437mm

$151

$128

$10

$101

$4

$32

$7

$4

Red River Units

Bakken Field

Other Rockies

Mid-Continent

Gulf Coast

Land

Seismic

Other

2007 Capex by Region ($mm)

$420

2

4

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Operational Overview

Mid-Continent

Proved reserves: 16.9 MMBoe

762 drilling locations

Gulf Coast

Proved reserves: 0.2 MMBoe

7 drilling locations

Red River

Units

56%

Bakken

Field

22%

Other

Rockies

8%

Mid-Continent

14%

Gulf Coast

<1%

Total proved reserves (12/31/06) = 118.3 MMBoe

74% PDP /  83% oil / 13.1 R/P / Operate 95% of PV-10%

Unconventional

78%

Red River

Units

45%

Bakken

Field

29%

Other

Rockies

6%

Mid-Continent

17%

Gulf Coast

3%

Avg. daily production (Q1 2007) = 27.9 MBoe/d

Unconventional

74%

1,589 gross wells / 1,772 drilling locations

Rockies

Proved reserves: 101.2 MMBoe

1,003 drilling locations

Proved Reserves by Geography

Production by Geography

Counties

with

acreage

holdings

are

highlighted

Regional office

Headquarters

5

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Key 2007 Drilling Projects

Development (50% drilling capex)

–

Red River Units

•

56% proved reserves / 45% production

–

Montana Bakken Shale

•

20% proved reserves / 29% production

Emerging Plays (42% drilling capex)

–

North Dakota Bakken

•

288,000 net undeveloped acres

–

Oklahoma Woodford Shale

•

45,000 net undeveloped acres

Red River

Units

MT

Bakken

ND

Bakken

Woodford

Counties with acreage    

holdings are highlighted

Regional office

Headquarters

Development

Emerging Plays

6

Pr ivate

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Conf idential

Red River Enhanced Recovery Units

66.5 MMBoe

proved reserves

12,599 Boe/d

net production in   

1st quarter 2007

Cedar Hills Discovered in 1995,

developed with horizontal drilling,

enhanced recovery operations

began in 2003

2007 Plans

–

$151MM 2007E capex

–

Infield horizontal drilling and re-entry

drilling program to accelerate production

and enhance sweep efficiency

–

Developing CHNU/CHWU on 320 acre

spacing per producer

Forecast peak production in late

2008 at about 20,000 net Boe/d

Cedar Hills North Unit

Cedar Hills West Unit

Buffalo Units

Medicine Pole

Hills West Unit

Medicine Pole

Hills South Unit

Medicine

Pole Hills

Unit

25 Miles

CLR operated units

Others units

7

Pr ivate

&

Conf idential

Montana Bakken

Shale

Significant  unconventional oil

resource play

–

Represents ½

of Montana’s oil

production

–

CLR is largest producer (7,685 boepd)

–

Developed through horizontal drilling

and advanced fracture stimulation

2007 Plans

–

$57 million 2007E drilling capex

–

Complete 640-acre development

–

Test un-booked upside

•

320-acre infill drilling

•

North expansion of field with       

tri-lateral 640-acre wells

•

Enhanced recovery 

–

Four drilling rigs

CLR  acreage

35 miles

Bakken producer

Williston    Basin

MT Bakken

31 wells

$57 mm

Outline of 

potential

Bakken

Production

8

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Conf idential

Richland County, Montana Infills

9

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Conf idential

North Dakota Bakken

Shale

Emerging  unconventional oil

resource play

–

526,000 gross (288,000 net)

undeveloped acres strategically located

on Nesson

Anticline

–

Significant reserve and production

growth potential

–

23 industry-operated drilling rigs

•

Amerada Hess

•

Conoco

Phillips

•

Marathon

2007 Plans

–

$71 million 2007E drilling capex

–

37 wells on 1280-acre locations in each

of 6 prospect areas

–

Five drilling rigs (two operated and

three Conoco

Phillips JV)

CLR  acreage

35 miles

Bakken producer

Filkowski

1-11H

( 63% WI )

300 bopd

Williston    Basin

Outline of 

potential

Bakken

Production

State Weydahl

44-36H   

( 33% WI )

560 bopd

Nelson Farms

( 13% WI )

350 bopd

State Veeder

44-36H    

( 38% WI )

380 bopd

Lovdahl

1-16H

( 36% WI )

250 bopd

10

Pr ivate

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Conf idential

ND Bakken

economic model

19%

26%

$60 / $6.00

Pre-tax IRR

23%

228

280

300

230

32%

256

315

336

259

$65 / $6.50

Pre-tax IRR

Net boe

(Mboe)

Gross boe

(Mboe)

Gross gas

(MMcf)

Gross oil

(Mbls)

$4.20 million D&C

33%

27%

228

280

300

230

19%

36%

$60 / $6.00

Pre-tax IRR

23%

199

245

264

201

44%

256

315

336

259

$65 / $6.50

Pre-tax IRR

Net boe

(Mboe)

Gross boe

(Mboe)

Gross gas

(MMcf)

Gross oil

(Mbls)

$3.66 million D&C

11

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New unconventional gas

resource play

–

40 industry-operated rigs

•

Newfield

•

Antero

•

Devon

–

45,000 net undeveloped acres

–

Significant reserve and

production growth potential

2007 Plans

–

$82 million 2007E drilling capex

–

123 gross (17 net) wells

–

Four drilling rigs now

–

Fifth rig to be added

Oklahoma Woodford Shale Project

6 miles

Outline of potential

Woodford production

07 CLR Locations

07 Woodford Horiz Spud

CLR Producer

Woodford Producer

CLR Acreage

Meyer Trust 1-13H

(34% WI)

1,655 Mcfd

Arlan 1-15H

(20% WI)

4,635 Mcfd

Harden 1-20H

(32% WI)

2,125 Mcfd

Holder 1-5H

(52% WI)

1,200 Mcfd

Pasquali 1-30H

(48% WI)

1,360Mcfd

Foster 1-6H

(17% WI)

2,685 Mcfd

Silva 20-1H

(1% WI)

4,865 Mcfd

12

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Conf idential

OK Woodford economic model

68%

47%

2,400

3,000

101%

68%

2,800

3,500

43%

$7.00

Pre-tax IRR

30%

$6.00

Pre-tax IRR

2,000

2,500

Net gas

(MMcf)

Gross gas

(MMcf)

$4.40 million D&C

50%

34%

2,400

3,000

73%

50%

2,800

3,500

21%

$6.00

Pre-tax IRR

32%

2,000

2,500

$7.00

Pre-tax IRR

Net gas

(MMcf)

Gross gas

(MMcf)

$5.00 million D&C

13

Pr ivate

&

Conf idential

Other ongoing and emerging plays

Rockies:

66 scheduled locations   

213,500 net undeveloped acres

Red River, Winnipegosis,

Fryburg, Phosphoria, Lewis

Shale

Midcontinent:

52 scheduled locations 

146,000 undeveloped acres

Morrow-Springer, Atoka,

Mississipian, Hunton, New

Albany Shale, Barnett Shale

Gulf Coast:

7 scheduled locations

6,400 net undeveloped acres

365,900 net undeveloped acres 

(50% of total undeveloped acreage)

Counties with acreage    

holdings are highlighted

Regional office

Headquarters

14

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Conf idential

2007 Plans

Grow production to 30,000+ boepd

–

24,707 boepd

in 2006

–

27,911 boepd

for first quarter 2007

Drill 285 gross (139 net) wells

–

34 net wells in ND Bakken

and OK Woodford

Maintain operating expense discipline

–

Production cost of approximately $6.85 per Boe

(guidance mid-point)

–

1Q production cost was $6.40 per Boe

Continue to build acreage in emerging resource plays

–

Increase scheduled drilling locations

–

Add future unconventional resource plays

Hedged 10,000 bopd

for Aug 2007 –

Apr 2008 at $72.90

–

$100,000+ per day increase in EBITDAX over analyst crude price deck

15

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Financial and Operating Summary

1 

See page 9 of the prospectus and first quarter 2007 earnings release for a reconciliation of net income to EBITDAX.

2

Operating statistics for 2006 computed on Boe sold.  Oil sales volumes are 21 MBbls less than oil production volumes for 2006.

Year ended December 31,

2004

2005

2006

1Q 2007

Realized oil price ($/Bbl)

$37.12

$52.45

$55.30

$48.48

Realized natural gas price ($/Mcf)

$5.06

$6.93

$6.08

$6.14

Oil production

(

boepd)

10,104

15,638

20,493

23,105

Natural g

as production

(Mcfd

)

24,093

24,674

25,274

28,835

Total production (boed)

14,121

19,751

24,707

27,911

EBITDAX

($

thousands)

1

$116,498

$285,344

$372,115

$90,996

Key Operational Statistics ($/Boe)

2

Oil and gas revenue

$35.20

$50.1

9

$52.09

$46.47

Production expense

8.49

7.32

6.99

6.40

Production tax

2.39

2.22

2.48

2.45

G&A (excluding non-cash equity compensation)

2.02

2.43

2.24

2.06

Total cash costs

$12.90

$11.97

$11.71

$10.93

Net operating margin

$22.30

$38.22

$40.38

$35.54

16

Pr ivate

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Conf idential

Summary

High quality, proved reserve base

–

Crude oil-concentrated, long-lived, high operated %

Track record of drill bit growth at low cost

–

Annual EBITDAX > Capex

over past 3 years

Low risk production growth in Red River Units

–

Production growth is 7,000+ boe/d

over next 2 years                                            

(~30% of 2006 average daily production for entire company)

Significant future production and reserve growth opportunities in

two large emerging plays

–

Over 1,500 unbooked

locations

Low cash costs with one of highest net operating margins among

E&P companies

–

$40.38 per Boe

($6.73 per Mcfe) net margin for 2006