CMT FirstEnergy Pres 17Nov10.PPT

5 downloads 292 Views 3MB Size Report
Nov 17, 2010 - ~CDN$580 MM ... STRONG FOCUSED LAND BASE OF LONG-LIFE ASSETS ... Asset base can achieve 20% ROR at $5.50/
First Energy/Société Générale Energy Conference V November 17, 2010

CORPORATE PROFILE

Operations

Calgary Based E&P Company Operating In Western Canada Sedimentary Basin (85% Natural Gas)

Exchange Listings

TSX

Symbol

CMT

Total Shares*

263 MM

Market Capitalization** ~CDN$124 MM Enterprise Value**

~CDN$580 MM

Trading Volume (daily average, TSX)

~0.5 MM (past 3 months) ~0.7 MM (past 6 months) ~0.9 MM (past 12 months)

Research Coverage

6 analysts

* ISSUED & OUTSTANDING ** PRICE OF $0.47/SHARE AS OF NOVEMBER 8, 2010

2

INVESTMENT VALUE

NATURAL GAS PRICE LEVERAGE STRONG FOCUSED LAND BASE OF LONG-LIFE ASSETS SIGNIFICANT OGIP FOR FUTURE VALUE

LOW-RISK, REPEATABLE RESOURCE PLAYS MAXIMIZING VALUE INCREASED CAPITAL EFFICIENCIES GENERATE MINIMUM 20% ROR IN LOWER HALF OF MID-CYCLE GAS PRICES CONTINUED IMPROVEMENTS IN COST STRUCTURE

EMERGING OIL POTENTIAL UPSIDE VALUE BY MOST METRICS UNDERVALUED RESERVE BASE TO NAV Poised for natural gas up-cycle – inexpensive entry point today 3

SUBSTANTIAL VALUE UPSIDE

EV / 2P Reserves

PRICE / NAV

Potential for multiple expansion w ith current trading Value of reserve potential to be realized in market 4

DRIVING COSTS DOWN

IMPROVEMENTS IN INTERNAL COST STRUCTURES (OPEX, ADMIN, INT) 16% REDUCTION IN 2009 FROM 2008 ADDITIONAL 13% DECREASE YEAR-TO-DATE IN 2010

IMPROVED CAPITAL STRUCTURE LOWER INTEREST RATES & CHARGES

SURPASSED MARKET EXPECTATIONS IN VOLUMES & COSTS FOR 3 QTRS

OPERATING EXPENSES

BANK DEBT & SENIOR TERM NOTES

ADMINISTRATIVE EXPENSES $900

$100

$30

$800

$80

*

$20

$60

$15

$40

$10

2008

2009

2010F

$700

$25

$MM

$MM

$35

$MM

$120

$600 $500 $400 $300

2008

2009

2010F

2008

2009

Nov/10*

GRAPH VALUE IS POST Q3 2010

5

IMPROVING EFFICIENCIES

GREATER OPERATING EFFICIENCIES & ECONOMICS IMPROVED HZ DRILLING & COMPLETION RESULTS DECREASED COSTS: $3.6 MM DCT (HISTORICAL) VS. $3.3 MM TODAY INCREASED HZ LENGTHS BY 20%

MEETING RESERVE VOLUME EXPECTATIONS WITH LOWER CAPITAL INVESTMENT 2010 CAPEX FORECAST NSAI* PDP ~ TP ~

$2 MM $35 MM

P+P ~ $73 MM CMT: $37 MM Q3 YTD *Includes capital for sold properties

6

Maximizing Resource Value

ASSET BASE – SOLID FOCUSED FOUNDATION

NATURAL GAS RESOURCE FOCUS LARGE, FOCUSED LAND BASE DEEP BASIN AREAS WITH 4 NATURAL GAS PLAYS 3 DEVELOPMENT LOW RISK AREAS: Niton, High River, Southern Plains 1 EMERGING EXPLORATION AREA: Callum/Cowley EMERGING OIL PLAY POTENTIAL SUBSTANTIAL GROWTH POTENTIAL MULTI-ZONE POTENTIAL REPEATABLE, LOW-RISK DEVELOPMENT ECONOMIES OF SCALE 21% BASE DECLINE RATE RESERVE BASE – DECEMBER 31, 2009 164 MM BOE P+P RESERVES VALUED AT $1.7 BILLION (PV10)

8

POTENTIAL LOCATIONS

AREA NITON

HIGH RIVER SOUTHERN PLAINS FOOTHILLS – CALLUM

FORMATION

5-YEAR PLAN

ESTIMATED CAPEX ($MM)**

Rock Creek

31

$102

Cardium

8

28

Other

46

92

Basal Quartz

27

124

Belly River*

185

87

Glauc./Mann.

50

38

Belly River

9

23

Cadomin

6

15

91

91

453

$600

OTHERS TOTAL * **

FOCUS IN SOUTHERN PLAINS SHIFTING TO DEEPER TARGETS BASED ON ESTIMATED AVERAGE WELL COST

Current inventory allow s for multiple years of development 9

BREAK-EVEN ANALYSIS (ROR 20%)

Required DCT Cost

Reserves

IP

Gas Price

($MM)

(BCF)

(MCF/D)

($/MCF)*

NITON

3.3

2.0

2,500

$3.94

HIGH RIVER

4.6

2.0

2,000

$5.34

0.47

0.185

180

$5.25

PLAY

SOUTHERN PLAINS * INCLUDES IMPACT OF 5% ORR

BASED ON ACTUAL DRILL, COMPLETE & TIE-IN COSTS (18 MONTHS) INCLUDES CHANGES TO ALBERTA ROYALTY STRUCTURE & DRILLING CREDITS DCT COST REFLECTS IMPROVED DRILLING COSTS

Asset base can achieve 20% ROR at $5.50/ MCF gas price Better cost efficiencies & higher prices strengthen economics 10

NITON – CENTRAL AB

INVESTMENT VALUE STRONG ECONOMICS IN LOW PRICE ENVIRONMENT GAS & LIGHT OIL PRODUCTION LIQUIDS RICH MULTIPLE ZONE POTENTIAL HIGHLY ACCRETIVE INFRASTRUCTURE CONTROL & FLEXIBILITY

AREA STATISTICS: LARGE LAND HOLDINGS ~130 GROSS SECTIONS, ~76% WI

RESERVES: TP: 16 MMBOE 2P: 28 MMBOE

2010 PLAN: 2010 DEVELOPMENT CAPITAL ~ 41% ~ 23 GROSS WELLS (COMBINATION OF NEW DRILLS & RECOMPLETIONS) 11

NITON – HORIZONTAL DRILLING

CMT POTENTIAL Formation

# Sections

# Locations

Cardium

Oil/Gas

10+

20+

Second White Specks

Oil/Gas

10+

2+

Viking

Gas

30+

40+

Notikewan

Gas

20+

6+

Spirit River

Gas

30+

50+

Ellerslie

Gas

50+

14+

Rock Creek

Gas

40+

31+

Currently testing other formations in 2010 for future potential 12

HIGH RIVER – SOUTHERN AB

INVESTMENT VALUE LARGE, DEEP BASIN RESERVOIR APPLY KNOWLEDGE GAINED AT NITON TO IMPROVE ECONOMICS BASAL QUARTZ: SIGNIFICANT POTENTIAL OGIP: ~ 550 – 700 BCF MULTIPLE PRODUCTIVE FORMATIONS CONTROL INFRASTRUCTURE

AREA STATISTICS: 90 GROSS SECTIONS, ~85% WI ~ 2 WELLS/SECTION SPACING TO DATE RESERVES: TP: 29 MMBOE 2P: 46 MMBOE

2010 PLAN: 2010 DEVELOPMENT CAPITAL ~ 26% ~ 4 GROSS WELLS (COMBINATION OF NEW DRILLS & RECOMPLETIONS)

13

HIGH RIVER - OGIP

OGIP (EST.) RECOVERY (CURRENT) CURRENT RECOVERY FACTOR REMAINING RESERVES REMAINING RECOVERABLE

550 – 700 BCF 123 BCF 18% - 22% 427 - 577 300 – 400 BCF

(ASSUME 70% RF)

CURRENT ESTIMATED DCT COSTS ~ $4.6 MM AT $5.34/MCF GAS PRICE, $4.6 MM YIELDS A 20% ROR

KEY TO VALUE ACCRETION IS DECREASING RLI THROUGH HZ DRILLING TP RLI = 19.2 YEARS 2P RLI = 30.4 YEARS

14

HIGH RIVER: BASAL QUARTZ DEVELOPMENT PLAN 9

2010

LOW RISK DEVELOPMENT DEFINED FORMATION 4 – 20 METRES THICK DEMONSTRATING PRODUCTION INCREASES WITH REFRACTURING

10

POTENTIAL

3

33

2011 2012

28

7

1

35

27

26

22

7 Wells 9 Wells

3

33

29

19

10

4

32

30

24

9

5

31

25

23

8

6

36

6 Wells 6 Wells

21

2013 2014

2

34

34

28

20

12

2

1

35

27

21

11

31

25

23

8

6

36

26

22

7

30

24

15

9

4

19

28

13

10

11

12

3

2

1

35

27

21

22

18

16

8

6

33

34

35

28

27

21

26

22

30

29

23

22

4

36

26

31

25

23

15

9

5

35

27

21

16

8

6

34

28

20

7

1

33

17

24

10

11

3

2

32

30

24

14

12

1

33

29

19

13

34

28

20

27

21

22

18N/29W 15

14

10

INITIAL RATE DEVELOPMENT:

13

11

3

Vertical IP = 560 MCF/D

36

26

22

23

24

24

19

20

1

35

27

21

12

2

34

28

13

11

3

33

29

14

10

4

32

30

15

9

5

31

25

16

8

6

36

25

17

7

1

Zero Porosity Edge 27

18

12

1

35

18N/28W

13

12

2

34

HZ IP = 2,700 MCF/D

36

26

22

17

7

8

29

19

15

9

32

30

24

16

5

31

25

23

18

6

17N/1W

10

4

3

33

34

28

20

35

27

21

26

22

23

17N/29W 15

14

10

PROGRAM

27

REFRACTURED 2 WELLS WITH GREAT RESULTS

22

23

24

24

19

20

1

35

27

21

12

2

34

28

13

11

3

33

29

14

10

4

32

30

15

9

5

31

25

16

8

6

36

25

17

7

1

36

26

18

12

1

35

17N/28W

13

12

2

34

DRILL 2 WELLS IN Q3/Q4 2010

13

11

3

36

26

22

17

16

7

8

9

5

31

25

23

18

6

24

33

29

19

15

28

20

10

11

2

34

35

27

21

14

3

4

32

30

16N/1W

31 POTENTIAL LOCATIONS IN 5-YEAR PLAN

2

32

18N/1W

SIMILAR TO CADOMIN DEVELOPMENT @ CUTBANK RIDGE

Evaluating follow-up locations

11

3

20

18

12

2

32

19

13

11

3

31

24

14

10

4

25

24

15

9

5

36

25

23

17

7

36

26

10

4

19N/28W

14

34

9

5

29

19N/1W 16

16

IF CUTBANK RESULTS REPLICATED, SIGNIFICANT IP UPSIDE & IMPROVED ECONOMICS

12

2-3 Wells 4

33

LESS THAN 30% OGIP RECOVERED

11

22

26

23

16N/29W 15

10

3

14

11

2

13

12

1

13

12

1

16N/28W 18

7

6

17

8

5

16

9

4

15

10

3

14

11

2

13

12

1

18

17

16

7

8

9

6

5

15

10

4

Starting to demonstrate economics & production increases 15

14

11

SOUTHERN PLAINS – SOUTHERN AB

INVESTMENT VALUE LARGE, MULTI-SAND SHALLOW GAS ZONES MULTIPLE PRODUCTIVE FORMATIONS CONTROL INFRASTRUCTURE

EMERGING OIL PLAY POTENTIAL AREA STATISTICS: 1,000 GROSS SECTIONS, 90% WI UP TO 4 WELLS/SECTION SPACING RESERVES: TP: 77 MMBOE 2P: 155 MMBOE

2010 PLAN: 2010 DEVELOPMENT CAPITAL ~ 25% ~ 12 GROSS WELLS (COMBINATION OF NEW DRILLS & RECOMPLETIONS)

16

SOUTHERN PLAINS – MULTIPLE PRODUCTIVE ZONES

CMT POTENTIAL Formation

# Sections

# Locations

Belly River

Gas

1,000

185

Glauconite/ Mannville

Oil/Gas

700

50

Success in developing Glauconite channels: yielded better than expected results 17

FOOTHILLS – SOUTHERN AB

INVESTMENT VALUE EXPLORATION PLAYS SIZE OF POTENTIAL STILL BEING DETERMINED FRACTURED TIGHT ROCK NATURAL FRACTURES REQUIRED FOR ECONOMIC PRODUCTION FOCUS ON IDENTIFYING OPTIMAL EXPLORATION STRATEGIES

AREA STATISTICS: 160 GROSS SECTIONS, 88% WI ~ 2 WELLS/SECTION SPACING RESERVES: TP: 5.4 MMBOE 2P: 14.5 MMBOE

2010 PLAN: 2010 DEVELOPMENT CAPITAL ~ 8% ~ 3 GROSS WELLS (COMBINATION OF NEW DRILLS & RECOMPLETIONS)

18

CALLUM/COWLEY – OGIP BASAL BELLY RIVER SAND

CALLUM 8-13-12-2W5

PLAY COMPARABLE TO HIGH RIVER UPPER SHEET BASAL BELLY RIVER SAND DEVELOPED THROUGH COMBINATION OF VERTICAL & HZ DRILLING AND REFRACTURES REDUCE RLI THROUGH OPTIMIZED HZ & VERTICAL DRILLING, COMPLETION TECHNIQUES

POTENTIAL EST OGIP ~ 14 BCF/SECTION LARGE PAY THICKNESS

BASAL BELLY RIVER SAND TVD 2,103 METRES

RESERVE LIFE INDEX: TP: 19.2 YEARS 2P: 51.2 YEARS

PROGRAM 2 GROSS WELLS DRILLED IN Q3 2010 9 POTENTIAL LOCATIONS IN 5-YEAR PLAN

Proving potential w ith new drills & recompletions 19

Emerging Oil Potential

20

SOUTHERN PLAINS EMERGING OIL PLAY

DEVELOPED VERTICALLY SURPLUS OF WELLS HISTORICALLY

HZ POTENTIAL TARGETING KNOWN OIL GLAUCONITE & ELLERSLIE FORMATIONS HZ & MULTI-STAGE FRACTURING SUBSTANTIAL EXISTING WELL KNOWLEDGE

CMT OPPORTUNITY MANNVILLE DEEP RIGHTS OVER 66% OF LAND

21

SOUTHERN PLAINS – ELLERSLIE & GLAUCONITE

ELLERSLIE PLAY VARIOUS SHEET SANDS

ACTIVITIES DRILLED VERTICAL TEST Q3 2010 Encouraging test results HZ WELL PLANNED IN Q4 2010/Q1 2011

POTENTIAL WITH SUCCESS ~ 2 – 3X MULTIPLIER PREDICTED WITH HZ WELL LARGE HZ DRILLING PROGRAM OPPORTUNITY BASED ON LAND SPREAD

GLAUCONITE PLAY MULTIPLE OIL PROSPECTS ACROSS LAND Based on mapping & offset production

ACTIVITIES FIRST HZ WELL PLANNED IN Q1 2011

POTENTIAL WITH SUCCESS LARGER HZ DRILLING PROGRAM IN 2011/ 2012

22

ELLERSLIE TYPE CURVE

TYPE CURVE CAPITAL (M$)

$2,500

(horizontal costs) Initial Rate (boepd)

230

Reserves (mboe)

363

RISKED Hz COS / COO (%)

50 / 50

ROR (%)

39.6

NPV (M$)

$1,086

Payout (years)

3.5

Capital Efficiency ($/boepd)

$23,145

F&D ($/boe)

$14.80

23

GLAUCONITE TYPE CURVE

TYPE CURVE CAPITAL (M$)

$1,850

(horizontal costs) Initial Rate (boepd)*

90

Reserves (mboe)

340

RISKED Hz COS / COO (%)

65 / 100

ROR (%)

46.3

NPV (M$)

$2,927

Payout (years)

3.0

Capital Efficiency ($/boepd)

$25,133

F&D ($/boe)

$9.87

* VERTICAL WELL RATE MULTIPLE INCREASE EXPECTED WITH HZ

SIX WELL NORMALIZED TYPE CURVE

24

ALBERTA BAKKEN POSITION, MONTANA

EMERGING OIL PLAY CANADIAN ACREAGE $145 MM SPENT ON LAND SINCE APRIL (crown)

Canadian Drilling US Drilling

84 miles

~ 450 SECTIONS @ AVE. $890/HA Maximum ~ $4,670/HA MAJOR PLAYERS:

Montana

Moun

US ACREAGE

hrust tain T

BLOOD INDIAN RESERVE MAJOR PLAYERS: Rosetta, Newfield

78 miles

Belt

CMT POSITION

Rocky

Crescent Point, Shell, Murphy

Alberta

kken Alberta Ba a Fairw y

79,000 ACRES (123 SECTIONS) LONG TENURE (EXPIRES 2017)

CMT

DISCUSSIONS WITH THIRD PARTIES DECISION TO DRILL, JV OR SELL 25

Looking Forward

26

2010 GUIDANCE

2010 Guidance Gas price, AECO $/GJ

$4.70

Crude oil price, Edmonton Sweet Light $/BOE

$78.39

Average daily production (BOED)

High end of range

(1)

16,000 – 16,500

Administrative expenses ($MM)

Low end of range

(1)

$25 - $27

Operating costs ($MM)

Low end of range

(1)

$80 - $85

Cash flow ($MM)

High end of range

(1)

~ $40 - $50

Capital expenditures

(2)

($MM, gross)

~ $60 - $70

(1) While maintaining guidance in the interim, Management expects further improvements in increasing production & reducing costs. (2) Includes development & corporate capital expenditures

SENSITIVITIES

IN CASH FLOW

Natural Gas +/-$0.25/MCF

$7.0 MM

Positioned to meet or beat targets in 2010 27

HEDGING STRATEGY

HEDGE UP TO 50% PRODUCTION CURRENTLY HEDGED 40% TO JUNE 2011 COLLARS WITH FLOOR/CEILING OF $4.50/$7.02/GJ

ELECTRICITY HEDGES SWAP FOR 84 MWH AT $50.74/MWH

CAPTURE VALUE FROM HIGH HEAT GAS PRODUCTION

CMT evaluating opportunities to increase hedging if opportunity is right 28

INVESTMENT VALUE & STRATEGY

LARGE RESERVE BASE OF LONG-LIFE, LOW-RISK ASSETS LAND, INFRASTRUCTURE, OPERATORSHIP, STRONG TECHNICAL TEAMS & SUCCESSFUL RESOURCE PLAYS POTENTIAL SIGNIFICANT IMPACT FROM MULTIPLE ZONES & HZ MULTI-STAGE FRACTURES DIVERSE ASSET BASE HAS LARGE AMOUNTS OF GAS ABLE TO MAINTAIN OR GROW PRODUCTION WITH MID-RANGE GAS PRICES (~$5.00 - $5.50) EMERGING OIL PLAY POTENTIAL

FOCUS ON VALUE CREATION & GROWTH OPPORTUNITIES EXECUTING STRATEGY & DELIVERING RESULTS Improving operating efficiencies & play economics Exceeded expectations in Q1, Q2 & Q3 2010

LARGE TAX POOLS OF ~ $930 MILLION DEBT LEVEL REDUCED & MANAGEABLE UPSIDE VALUE BY MOST METRICS

Significant value obtained from existing asset base w ith minimal exploration risk 29

FORWARD LOOKING STATEMENTS Certain information regarding the company contained herein constitutes forward-looking information and statements and Financial outlooks (collectively, “forward-looking statements”) under the meaning of applicable securities laws, including Canadian Securities Administrators’ National Instrument 51-102 Continuous Disclosure Obligations and the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance, or other statements that are not statements of fact, including statements regarding (i) cash flow and capital and operating expenditures, (ii) exploration, drilling, completion, and production matters, (iii ) results of operations, (iv) financial position, and (v) other risks and uncertainties described from time to time in the reports and filings made by Compton with securities regulatory authorities. Although Compton believes that the assumptions underlying, and expectations reflected in, such forward-looking statements are reasonable, it can give no assurance that such assumptions and expectations will prove to have been correct. There are many factors that could cause forward-looking statements not to be correct, including risks and uncertainties inherent in the Company’s business. These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate fluctuations, availability of services and supplies, operating hazards, access difficulties and mechanical failures, weather related issues, uncertainties in the estimates of reserves and in projection of future rates of production and timing of development expenditures, general economic conditions, and the actions or inactions of third party operators, and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by Compton. Statements relating to “reserves” and “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. The forward-looking statements contained herein are made for the purpose of generally disclosing Compton’s views of its prospective activities. Compton may, as considered necessary in the circumstances, update or revise the forward-looking statements, whether as a result of new information, future events, or otherwise, but Compton does not undertake to update this information at any particular time, except as required by law. Compton cautions readers that the forward-looking statements may not be appropriate for purposes other than their intended purposes and that undue reliance should not be placed on any forward-looking statement. The company’s forward-looking statements are expressly qualified in their entirety by this cautionary statement. USE OF BOE EQUIVALENTS The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“boe”) basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. We use the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip. However, boes do not represent a value equivalency at the plant gate where we sell our production volumes and therefore may be a misleading measure if used in isolation.

30

COMPTON PETROLEUM CORPORATION Suite 500, Bankers Court

Tel: 403.237.9400

850 Second Street SW

[email protected]

Calgary, Alberta, Canada T2P 0R8

www.comptonpetroleum.com

v

TSX:CMT

Supplementary Information

32

NITON: ROCK CREEK DEVELOPMENT PLAN

WELL DEFINED RESERVOIR LOW RISK BETTER USE OF TECHNOLOGY

INCREASED ROR EST ROR: 24% @ 85% COS RECOVERY/WELL = 2.0 BCF HIGHER IP’S FROM 2.0 TO 3.0 MMCF/D* DRILL COSTS REDUCED BY 15% - 20% WITH 20% INCREASE IN HZ SECTIONS

2010 PROGRAM DRILLED 5 WELLS @ 100% SUCCESS 3 HORIZONTAL GAS WELLS IN Q4 2010

Rock Creek New Drills

LEGEND

* AVERAGE JUNE 2009 VS. MAY 2010

Rock Rock Rock Rock Rock

Creek Creek Creek Creek Creek

2010 2011 2012 2013 2014

33

NITON: ELLERSLIE DEVELOPMENT PLAN

WELL DEFINED PRODUCTIVE TRENDS

T56

DEVELOPED USING VERTICAL WELLS EARLY STAGE POTENTIAL DEVELOPMENT FOR HZ WELLS

T55

FOCUSED ON IMPROVING ECONOMICS T54

EST ROR: 36% @ 50% COS OGIP = 1,026 MMCF IP’S ~ 1.0 MMCF/D

T53

~ $1.5 MM DCT APPLY KNOWLEDGE GAINED WITH ROCK CREEK

T52

PROGRAM DRILL 1 WELL IN 2010 14 POTENTIAL LOCATIONS IN 5-YEAR PLAN

T51

R15

R14

R13

R12W5

34

NITON: CARDIUM DEVELOPMENT PLAN

RECENTLY DEVELOPING ZONE GAS & OIL CHARGED AREAS

R15

R13

R12W5

T55

T55

Gas storage Unit

APPLYING TECHNOLOGY TO FORMATION

POTENTIAL

R14

T54

T54

Shelf sandstones and shales

EST OGIP ~ 32+ BCF

gas-bearing sandstones

EST OOIP ~ 17+ MMBBL Shoreline conglomerates

APPLY KNOWLEDGE GAINED FROM PARTNERS IN AREA (E.G. VERO)

T53

T53

Oil-bearing sandstones

PROGRAM 20 POTENTIAL LOCATIONS T52

T52

T51

T51

EVALUATING FORMATION

R16 File: Niton New CRDM ppt.MAP

R15

R14 Datum: NAD27

R13 Projection: Stereographic

R12W5 Center: N53.59940 W115.95569

Created in AccuMap™, a product of IHS

35

NITON: SPIRIT RIVER DEVELOPMENT PLAN

R15

R14

R13

R12W5

NEW ZONE EARLY STAGE OF RESERVOIR DEVELOPMENT CURRENT PRODUCTION IS FROM 12 VERTICAL WELLS

T55

T55

T54

T54

T53

T53

SIMILAR TO SPIRIT RIVER WILRICH PLAY (DEVELOPED BY FAIRBORNE & OTHERS TO THE WEST & NW)

POTENTIAL HZ WELL PROFILE EST ROR: 22% @ 50% COS OGIP = 2,920 MMCF IP’S ~ 2.5 MMCF/D ~ $3.4 MM DCT

PROGRAM TIE-IN 1 WELL IN Q4 2010 50 POTENTIAL LOCATIONS

R15 File: Niton New SPRV.MAP

R14 Datum: NAD27

Projection: Stereographic

R13 Center: N53.66956 W115.93434

Created in AccuMap™, a product of IHS

36

HIGH RIVER RESERVOIR MODEL

HETEROGENEOUS RESERVOIR WITH EVIDENCE OF COMPARTMENTALIZATION SANDS WITH MULTI-STAGE CHANNELLING EARLY STAGE SANDS HAVE RELATIVELY CONTIUOUS POROSITY AT TYPICAL WELL SPACING LATE STAGE CHANNEL SYSTEM HAS VARIABLE POROSITY

WELL TYPE DEPENDENT ON CHANNEL NOT ALL LOCATIONS BEST ACCESSED BY VERTICAL WELLS HZ DRILLING MAY INCREASE ECONOMICS OF LOWER PERMEABILITY SANDS

RESERVOIR LIMITS WELL DEFINED Combination of vertical & horizontal drilling strategy to access different channel characteristics 37

SOUTHERN PLAINS: BELLY RIVER DEVELOPMENT PLAN R29

REPEATABLE, LOW RISK PRODUCTION MULTIPLE SANDS

R28

R27

R26

R25

R24

R23

R22

R21W4

T24

T24

T23

T23

T22

T22

INEXPENSIVE DRILLING

2010 Drills T21

T21

T20

T20

T19

T19

T18

T18

T17

T17

T16

T16

T15

T15

T14

T14

POTENTIAL IMPROVE ECONOMICS

PROGRAM 6 GROSS WELLS IN 2010 185 POTENTIAL LOCATIONS IN 5YEAR PLAN

R29 File: SAbActivity.MAP

R28 Datum: NAD27

R27

R26

Projection: Stereographic

R25

R24

Center: N50.61256 W113.43031

R23

R22W4 Created in AccuMap™, a product of IHS

38

SOUTHERN PLAINS: GLAUC./MANN. DEVELOPMENT PLAN

INCREASED ROR POTENTIAL FOCUS ON DEEPER PLAYS EVALUATE OIL PLAYS

POTENTIAL

R24

R23

R22

R21W4

T19

T19

EXTEND LIFE OF AREA SUCCESSFULLY EXPLOITED BY OTHER OPERATORS

2010 Drills T18

T18

GEOLOGICALLY SIMILAR ZONES IN OTHER PARTS OF ALBERTA

2010 Recompletions

PROGRAM 6 GROSS WELLS IN 2010 (2 DRILLS/ 4 RECOMPLETIONS) 3 WELLS TO DATE YIELDED BETTER THAN EXPECTED RESULTS

T17

T17

R24 File: Presentation2010BellyRiver.MAP

R23 Datum: NAD27

Projection: Stereographic

R22W4 Center: N50.51971 W113.06426

Created in AccuMap™, a product of IHS

50 POTENTIAL LOCATIONS

39