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