Continental Resources Inc (CLR) 8-K The Oil & Gas Conference

The Oil & Gas Conference

Denver, Colorado

August 22, 2007

Exhibit 99.1

1

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

Company Overview

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

–

$2.5

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

–

>500 hz

wells drilled targeting unconventional formations

–

77% of production from unconventional resources

–

>700,000 net undeveloped acres concentrated in emerging plays

Strong financial position

–

$137

million of bank debt outstanding

–

2007E

cash

flows

to

substantially

fund

$482mm

capital

budget

3

$94

$145

$327

$482

2004

2005

2006

2007E

Investment in Asset Base

Capex ($mm)

14,121

19,751

24,707

28,610

2004

2005

2006

Q2 '07

Production (Boe/d)

$116

$285

2004

2005

2006

2007E

EBITDAX

1

($mm)

1

See second 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 = $482mm

$131

$91

$71

$17

$79

$19

$11

$26

$37

Red River Units

MT Bakken

ND Bakken

Other Rockies

Woodford

Other Mid-Con

Facilities

Land

Other

2007 Capex by Region ($mm)

$420 ²

4

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

44%

Bakken

Field

31%

Other

Rockies

6%

Mid-Continent

17%

Gulf Coast

2%

Avg. daily production (Q2 2007) = 28.6 MBoe/d

Unconventional

77%

1,589 gross wells / 1,772 drilling locations

Rockies

Proved reserves: 101.2 MMBoe

1,003 drilling locations

Proved Reserves by Geography

Counties

with

acreage

holdings

are highlighted

Regional office

Headquarters

Production by Geography

5

Key 2007 Drilling Projects

Development (54% drilling capex)

–

Red River Units

•

56% proved reserves / 44% production

–

Montana Bakken Shale

•

20% proved reserves / 28% production

Emerging Plays (37% 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

Red River Enhanced Recovery Units

66.5 MMBoe

proved reserves

12,680 Boe/d net production in   

2nd quarter 2007

Cedar Hills discovered in 1995,

developed with hz

drilling, 2003

enhanced recovery operations

2007 Plans

–

$131MM 2007E drilling 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

–

Badlands Plant begin in August

Forecast peak production in late

2008 at ~ 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

Montana Bakken Shale

Significant  unconventional oil

resource play

–

Represents ½

of Montana’s oil

production

–

CLR is largest producer (7,890 boepd)

–

Developed through horizontal drilling

and advanced fracture stimulation

2007 Plans

–

$91

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

47 wells

$91 mm

Outline of 

potential

Bakken 

Production

8

Richland County, Montana Infills

CLR  acreage

Sonja 1-23H

Tri-Lateral

93% WI

Avg

245 bopd

first 35 days

Bidegaray

1-10H

Tri-Lateral

Testing 200+ bopd

(83% WI)

Edgar 1-34H

Tri-Lateral

Drilling

(75% WI)

Tri-Lateral

Scheduled

(95%WI)

Patricia 1-28H

Tri-Lateral

Testing 200+ bopd

(95%WI)

Hazel 1-18H

Tri-Lateral

Drilling

(95% WI)

Tri-Lateral

Scheduled

(17% WI)

Dorothy #3H

320 test drilling

(77% WI)

Third 320

scheduled

(95% WI)

Margaret 3-15H

First 320 acre

well

9

MT Bakken economic models

17%

23%

$60 / $6.00

Pre-tax IRR

22%

183

225

243

185

29%

203

250

270

205

$65 / $6.50

Pre-tax IRR

Net boe

(Mboe)

Gross boe

(Mboe)

Gross gas

(MMcf)

Gross oil

(Mbls)

$3.6 million D&C 640-acre tri-lateral wells

20%

15%

163

200

216

153

47%

$60 / $6.00

Pre-tax IRR

58%

244

300

324

246

$65 / $6.50

Pre-tax IRR

Net boe

(Mboe)

Gross boe

(Mboe)

Gross gas

(MMcf)

Gross oil

(Mbls)

$3.3 million D&C 320-acre infield wells

10

North Dakota Bakken Shale

CLR  acreage

Bakken producer

35 miles

Filkowski

1-11H

( 63% WI )

246 bopd

Williston    Basin

State Weydahl

44-36H   

( 33% WI )

560 bopd

Nelson Farms

( 13% WI )

350 bopd

State Veeder

44-36H    

( 38% WI )

344 bopd

Lovdahl

1-16H

( 36% WI )

250 bopd

Brown 44-

1H

( 35% WI )

519 bopd

Candee

11-9H

( 48% WI )

386 bopd

Emerging  unconventional oil

resource play

–

526,000 gross (288,000 net) undeveloped

acres strategically located on Nesson

Anticline

–

Significant reserve and production growth

potential

–

ND oil prod. highest in 20 years

–

20+ industry-operated rigs

•

Amerada Hess

•

Conoco

Phillips

•

Marathon

2007 Plans

–

$71 million 2007E drilling capex

–

41 wells on 1280-acre locations in each of

6 prospect areas

–

Five drilling rigs (two operated and three

Conoco

Phillips JV)

Outline of

potential

Bakken

production

11

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 –

dual leg lateral

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 –

single leg lateral

12

New unconventional gas

resource play

–

40+ industry-operated rigs

•

Newfield

•

Antero

•

Devon

–

45,000 net undeveloped acres

–

Significant reserve and

production growth potential

–

Caney Shale upside

2007 Plans

–

$79 million 2007E drilling capex

–

~100 gross (14 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 hz

Spud

CLR Producer

Woodford Producer

CLR Acreage

7-day average IP rates

Meyer Trust 1-13H

(34% WI)

1,655 Mcfd

Arlan 1-15H

(20% WI)

4,645 Mcfd

Harden 1-20H

(32% WI)

2,125 Mcfd

Holder 1-5H

(52% WI)

1,204 Mcfd

Pasquali 1-30H

(48% WI)

1,360 Mcfd

Foster 1-6H

(17% WI)

2,685 Mcfd

Silva 20-1H

(1% WI)

4,865 Mcfd

Pratt 1-17H

(23% WI)

3,752 Mcfd

13

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 --

operated

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 --

non-operated

14

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,

Trenton/Black River

365,900 net undeveloped acres 

(50% of total undeveloped acreage)

Counties with acreage    

holdings are highlighted

Regional office

Headquarters

Gulf Coast:

7 scheduled locations

6,400 net undeveloped acres

15

2007 Plans

Grow production to 30,000+ boepd

–

24,707 boepd

in 2006

–

28,610 boepd

for second quarter 2007

Drill ~300 gross (160 net) wells

–

Expect good year in reserve additions

Maintain high cash operating margin

–

$40.38 / Boe ($6.73 / Mcfe) net margin for 2006

–

$38.34 / Boe ($6.39 / Mcfe) net margin for 1H 2006

Hedged 10,000 bopd

for Aug 2007 –

Apr 2008 at $72.90

–

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

Continue to build acreage in emerging resource plays

–

Increase scheduled drilling locations

–

Add future unconventional resource plays

16

Financial and Operating Summary

1 

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

2

Operating statistics per Boe sold.  Oil sales volumes are 21 MBbls and 47 MBbls less than oil production volumes for 2006 and 2007, respectively.

Year ended December 31,

2004

2005

2006

1H

2007

Realized oil price ($/Bbl)

$37.12

$52.45

$55.30

$53.44

Realized natural gas price ($/Mcf)

$5.06

$6.93

$6.08

$6.11

Oil production

(boepd)

10,104

15,638

20,49

3

23,391

Natural gas production

(Mcf

d)

24,093

24,674

25,274

29,229

Total production (boed)

14,121

19,751

24,707

28,262

EBITDAX

($

thousands)

1

$116,498

$285,344

$372,115

$199,655

Key Operational Statistics ($/

Boe)

2

Oil and gas revenue

$35.20

$50.19

$52.09

$50.52

Production expense

8.49

7.32

6.99

7.43

Production tax

2.39

2.22

2.48

2.68

G&A (excluding non

-cash equity compensation)

2.02

2.43

2.24

2.07

Total cash costs

$12.90

$11.97

$11.71

$12.18

Net operating margin

$22.30

$38.22

$40.38

$38.34

17

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

–

7,000+ Boe/d expected production growth 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 –

ND Bakken and OK Woodford Shales

–

Over 1,500 unbooked

locations

Low cash costs with one of highest net operating margins

–

Significant valuation and competitive advantage