Corporate Presentation
October 2014
TSX:
TSX:YGR
YGR
• Our job is to create shareholder value
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Integrity and ethical behavior are essential to success
Sound ethics and shareholders interests are compatible
It is okay to be wrong: own it, accept it, learn from it
Embrace adversity, it is a difficult business
Diversity of skill-sets within the team are critical to success
Loyalty, performance and achievement are recognized
Top decile performance in all categories is the goal
• Full cycle Corporate IRR is what measures our success
TSX: YGR
2
Publicly listed junior oil and gas company
TSX: YGR
Shares Outstanding
Basic
Options/Warrants (weighted average $1.87)
57.7 million
4.9 million
Fully Diluted
62.6 million
Insider Ownership
Basic
Fully Diluted
15%
21%
Market Capitalization (at $2.50/share)
$145 million
Q2 Net Debt ($90 million in ATB credit facilities)
$41 million
Enterprise Value
$186 million
Q2/2014 net debt to annualized cash flow
1.3 : 1
Forecast Q4/2014 net debt to annualized cash flow
0.85 : 1
Future drilling locations (Cardium & Glauc) - Current
188 Gross (141 net)
Proved plus Probable Reserves @ Dec 31, 2013 (Deloitte)
Net Present Value @ 10% (P+P) @ Dec 31, 2013
NAV / Share (with no undeveloped land value) @ Dec 31, 2013
TSX: YGR
17.5 million boe
$251 million
$4.20
3
Management Team
Jim Evaskevich, President & CEO
Randall Faminow, VP, Land
Lorne Simpson B.Sc., C.E.T., VP, Operations
James Glessing, CA, CFO
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30+ years extensive executive experience with strong
operations background
30+ years experience in the industry
Supervisor, Drilling Ops with PetroBakken Energy Ltd.
Engineered, drilled or completed 250 HZ Cardium
wells, 200 HZ Bakken wells, 2 HZ Duvernay wells, 25
HZ Montney wells, and dozens of Blue Sky, Viking,
SWS, Glauc, and Rock Creek HZ wells
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30+ years of experience in all aspects of oil and gas land work,
including negotiation, acquisitions and divestments, contracts
and mergers
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15+ years oil and gas accounting experience
Executive and financial experience as CFO with North Peace
Energy Corp
Controller at BlackRock Ventures,
Canadian Natural Resources, Shell and Deloitte
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Board of Directors
Gordon Bowerman
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Chairman
President of Cove Resources Ltd
Founder of several successful private and public oil
and gas companies
Robert Weir
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President of Weir Resource Management Ltd
Jim Evaskevich
•
President and CEO of Yangarra Resources Ltd
TSX: YGR
Neil Mackenzie
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Director of various public companies, including Canyon
Technical Services
Currently a partner in Blackstone Fluids, an oil and gas
drilling fluids company
Ted Morton
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A former Canadian politician and cabinet minister in
the Alberta government
Has held various positions in the Alberta Government
included Minister of Energy (2011-2012), Minister of
Finance and Enterprise (2010-2011), and Minster of
Sustainable Resources (2006-2010)
4
Half Cycle IRR (1)
Full Cycle IRR (2)
80%
70%
60%
IRR
50%
40%
67%
30%
41%
20%
10%
24%
34%
12%
65%
26%
31%
0%
2010
1.
2.
TSX: YGR
2011
2012
2013
Half cycle IRR is based on actual drilling and completion costs, production to date and P+P reserves.
Full cycle IRR allocates all other capital costs to the wells (i.e. land, G&G, infrastructure)
5
Completion cost per stage
Drilling cost per meter
$250,000
$800
$700
$200,000
$600
$500
$150,000
$400
$100,000
$300
$200
$50,000
$100
$0
$0
2010
2011
2012
2013
2010
Q2 2014 Operating costs/boe versus peers
2012
2013
Q2 2014 G&A/boe versus peers
10.00
8.00
Average $17.46
6.00
Average $4.53
4.00
2.00
TSX: YGR
YGR
0.00
YGR
35.00
30.00
25.00
20.00
15.00
10.00
5.00
0.00
2011
6
4,000
40,000,000
3,000
30,000,000
2,000
20,000,000
H2 Estimate
10,000,000
Cashflow
1,000
Production
0
0
2010
2011
2012
2013
0.90
0.00007
Production per Share
0.00006
(mboe)
(Cashflow)
50,000,000
2014 (est)
Cashflow per Share
0.80
0.70
0.00005
0.60
0.00004
0.50
0.00003
0.40
0.00002
0.30
0.20
0.00001
0.10
-
2010
TSX: YGR
2011
2012
2013
2014
-
2010
2011
2012
2013
2014
7
P+P Reserves (mboe)
20,000
300
Reserve Value PV10 ($ millions)
250
15,000
Oil
10,000
NGL's
5,000
Natural gas
0
2010
2011
2012
200
150
100
50
0
2013
2010
2011
2012
2013
Reserve Value PV10 ($ millions)
P+P Reserves (mboe)
300
20,000
250
15,000
200
PROB
10,000
PUD
PDNP
5,000
PDP
0
2010
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2011
2012
2013
150
100
50
0
2010
2011
2012
2013
298% increase in reserves since 2010 (86% per share)
Replaced 2013 production by 614% (546% in 2012)
Finding and development recycle ratio of 2.57 times on P+P reserves
Finding and development costs of $14.07/boe on proved plus probable reserves
Reserve life index of 16.0 years
Future development costs of $125 million
TSX: YGR
8
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Increased stage count in laterals from 10 to 24
Gone from 250 tonnes of sand/well to 540 tonnes of sand/well
Full mile laterals on all wells with longer reach wells in inventory
Resin-coated sand tailed in to prevent crushing
Premium casing reduces friction when pumping fracs, minimizes
casing failures
Tighter well spacing on sections to maximize recoveries
Mono-bore drilling reduces drilling times and drilling costs
Nano technology in drilling mud to help heal loses
Multi-well Pad drilling to reduce the cost per well
Multi-well pads allow for zipper fracs
TSX: YGR
9
CAPEX budget for 2014
$75.0 million
• Budget focused on Central Alberta
• Includes $5 million of Duvernay spending
• Funded with cash flow and the existing credit facilities
2014 Guidance
Production (boe/d)
Annual Average
Cash flow from operations
Debt to Annualized Q4 cash flow
Pricing Assumptions (annual average)
Crude oil – Edmonton Par
Natural Gas
Corporate decline assumptions
TSX: YGR
3,300 boe/d
$47 million
0.85 : 1
$90.00/bbl
$3.50/GJ
40% in year one
15% thereafter
10
Central Alberta
• Interest in 140 sections of land
• 70 + horizontal wells drilled since
2010
•
Pembina
Edmonton
Willesden Green
Ferrier
Rocky Mountain House
Red Deer
Focus
• Cardium and Glauc plays
• Light oil
• High netback
• Quick payouts
Calgary
TSX:
TSX:YGR
YGR
11
Cardium
5m
Second White Specks
30m
Viking
5m
Colorado Group
650m thick
•
Vertical production
exists in all zones
•
All zones meet the
criteria for horizontal
drilling
Glauconitic
Ellerslie
Rock Creek
20m
10m
15m
Duvernay
TSX:
TSX:YGR
YGR
12
Cardium
Future Drilling Locations
Locations booked in 2013 Reserve Report
(1) Present value of future cash-flow, discounted at 10%, net of Drill, Complete and Equipping costs.
147 gross (107 net)
35 gross (29 net)
Drill, Complete and Equip
$2.7 million – $3.2 million
Average: $2.9 million
NPV10 ($90/bbl & $4.00/mcf) (1)
$2.4 million – $4.7 million
Average: $3.3 million
IRR – Half cycle before tax
Payout
Capital Efficiency (IP 365)
67% – 172%
Average: 106%
8 months – 16 months
Average: 13 months
$6,500 – $27,000
$14,850
Glauconite
Future Drilling Locations
41 gross (34 net)
Locations booked in 2013 Reserve Report
11 gross (8 net)
Drill, Complete and Equip
$3.0 million – $3.5 million
Average: $3.3 million
NPV10 ($90/bbl & $4.00/mcf) (1)
$2.9 million – $6.3 million
Average: $3.7 million
IRR – Half cycle before tax
Payout
Capital Efficiency (IP 365)
Total Cardium & Glauc Locations
TSX: YGR
75% – 188%
8 months – 13 months
Average: 122%
Average: 11 months
$7,500 – $12,000
$10,250
188 gross (141 net)
13
T45
T45
T45
T44
T44
T44
R
UPP
WE
LO
T43
ER
Y
CAR
OIL
SS
M
IU
RD
CA
GA
T43
T43
M
DIU
T42
W
LO
W
IL
E
R
T42
LE
SD
EN
T42
R
A
C
G
R
M
IU
D
T41
C
A
R
D
IU
M
PROSPECT
IVE UPPER
FI
EL
D
Z
IU
D
H
R
A
C
T41
EE
N
T41
M
LOWER
IL
O
PROSPECTIVE
CARDIUM
HZ OIL
T40
GAS
T40
T40
RI
R
FE
PE
CT
L
H
Z
T39
D
EL
FI
PROSPECTIVE
HZ
GAS
Working
M
T39
cardium wtr inj
cardium gas
cardium oil
IU
IL
O
E
V
TI
Wells
T38
RD
CA
IV
E
OI
EC
SP
Legend
O
PR
HZ
ER
PR
OS
T39
Legend
Wells
cardium wtr inj
cardium gas
cardium oil
PROSPECTIVE
HZ
yangarra land
Farmin land
OIL
T38
T38
Working
yangarra land
Farmin land
T37
Cardium Show Map
cardium pool outlines
T37
T37
By : Poruchny
Scale = 1:85000
Cardium Show Map
cardium pool outlines
Date : 2013/12/04
Project : cardium show map
By : Poruchny
Scale = 1:85000
R9
TSX:
TSX:YGR
YGR
R8
R7
R6
Date : 2013/12/04
Project : cardium show map
R5W5
14
T42
T42
T43
T43
T43
T41
T41
D
T42
T42
Y
LE
A
O
H
Y
LE
A
B
R
D
any cut amount
T41
T41
LA
IS
T39
IE
O
H
CHANNEL
D
N
T40
A
B
D
A
T41
R
T42
I
R
R
T40
R
ER
N
LA
IS
T39
LA
T40
T38
T38
T40
CHANNEL
any cut amount
Y
LE
T39
any cut amount
T37
H
T37
R
R
IS
T40
D
A
O
CHANNEL
B
A
R
IE
D
N
T39
T39
T38
R9
R8
R7
R6
R5
R4
R3W5
Legend
Wells
Glauconite Show Map
Porosity Trends
glauc @TD
glauc pens
HZ glauc liquid rich gas
All Glauc liquid rich gas
Working
T38
T38
T37
CHANNEL
Yangarra land
R4
By : Poruchny
Scale = 1:85000
any cut amount
Date : 2013/12/04
Project : glauc show map2
R3W5
Glauconite Show Map
Porosity Trends
By : Poruchny
Scale = 1:85000
T37
T37
Date : 2013/12/04
Project : glauc show map2
R9
R8
R7
R6
R5
R4
R3W5
Legend
Wells
TSX: YGR
glauc @TD
glauc pens
HZ glauc liquid rich gas
Glauconite Show Map
Porosity Trends
15
•
Significant amounts of
oil have been produced
over the past 30 years
from vertical wells
•
10 to 20 million barrels
of Original Oil in Place
(OOIP) per section
•
Accumulated 45 gross
(35 net) sections
•
Yangarra has 3
horizontal wells and 2
vertical wells in the SWS
formation
Yangarra Land
TSX: YGR
16
•
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•
•
Let industry de-risk the play
Continue land-base to 2020 with strat test wells
Larger players are migrating to the Duvernay which may
provide opportunities in plays like the Cardium and Glauc in
Central Alberta
Our first strat test well is planned for 2014
Continue to collect data and further de-risk Yangarra’s
acreage
The Duvernay represents option value
that is not reflected in the current share price
TSX: YGR
17
•
Early production rates show initial
liquids yields up to 200 bbl/MMcf
•
Duvernay operators are still
establishing Best Practices for
Drilling and Completion
•
Production data supports the
emergence of an economically
attractive liquids fairway
•
Geological parameters (mineralogy,
thickness, HC potential, TOC,
fractures, brittleness, net pay, etc.)
are generally known from industry
activity/results, public
data/analysis and YGR proprietary
work
•
Reservoir Characteristics evolving
•
Local variations in rock
properties/well performance can
be expected with further drilling
TSX: YGR
YGR Acreage
18
•
Very Active Areas with
high capital investment
currently by majors and
large independents
•
North Block primarily in
liquids window with new
horizontal drilling by
Vermillion/Black Swan
immediately offsetting (2
miles) YGR land
•
YGR
NORTH BLOCK
South Block surrounded
by drilling activity (Shell,
Encana, Talisman, Black
Swan Swan/Paramount)
YGR
SOUTH
BLOCK
TSX: YGR
19
• Acreage within the
liquids/volatile oil fairway
YGR
NORTH
BLOCK
YGR
SOUTH
BLOCK
• South Block (Willesden Green)
• 7 Net Sections
• Net Pay ~ 36 m
• OGIP ranges from 70 to
100 BCF/sec
• North Block (Pembina)
• 54 Net Sections
• Net Pay ~ 20 to 24 m
• OGIP ranges from 40 to 50
BCF/sec*
*OGIP estimated internally using geochemical, petrophysical and geomechanical analyses of offset wells and proprietary reservoir studies
TSX: YGR
20
YGR acreage is optimal with high average porosity > 6%
YGR Acreage
TSX: YGR
21
R9
R8
R7
R6
R5
R4W5
T43
T43
ECA 102 WILLGR 6-3-43-6
ECA HZ WILLGR 3-6-43-7
MOSAIC WILSONCK 13-35-42-5
ECA 102 HZ WILLGR 8-5-43-6
ECA WILLGR 16-33-42-6
ECA HZ WILLGR 11-33-42-6
T42
T42
ECA HZ WILLGR 12-10-42-7
ECA HZ WILLGR 1-9-42-7
ECA HZ WILLGR 7-3-42-7
TALISMAN 02 HZ WILLGR 12-32-41-5
ECA HZ FERRIER 15-33-41-8
ECA 104 WILLGR 8-35-41-7
SCL
SCLHZHZ102
FERRIER
FERRIER
7-35-41-9
6-35-41-9
ECA HZ WILLGR 2-35-41-7
ECA HZ FERRIER 4-32-41-8
TALISMAN 02 HZ WILLGR 4-33-41-5
TALISMAN 03 HZ WILLGR 4-33-41-5
ECA 102 HZ WILLGR 16-27-41-7
ECA HZ FERRIER 6-27-41-8
T41
ECA HZ WILLGR 8-19-41-6
SCL
SCLHZHZ103
FERRIER
FERRIER
1-24-41-9
2-24-41-9
T41
TALISMAN HZ WILLGR 16-15-41-5
ECA HZ FERRIER 10-16-41-8
TALISMAN HZ WILLGR 10-3-41-5
TALISMAN 02 HZ WILLGR 7-6-41-5
TALISMAN HZ WILLGR 4-1-41-6
SCL HZ FERRIER 15-31-40-7
SCL FERRIER 8-30-40-7
SCL HZ FERRIER 7-30-40-7
SCL HZ FERRIER 3-21-40-7
SCL HZ 102 FERRIER 4-21-40-7
T40
SCL HZ FERRIER 16-18-40-8
TALISMAN HZ WILLGR 13-35-40-5
SCL HZ FERRIER WILLGR 16-13-40-7
SCL 102 HZ FERRIER WILLGR 15-13-40-7
T40
SCL HZ FERRIER 16-12-40-8
SECURE FERRIER 10-7-40-8
SCL HZ FERRIER 7-11-40-7
SCL HZ FERRIER 6-11-40-7
SCL HZ FERRIER 4-2-40-8
SCL HZ 102 FERRIER 4-4-40-8
SCL HZ 102 FERRIER 12-31-39-7
SCL HZ FERRIER 9-36-39-8
SCL HZ 102/ WILLGR 10-27-39-6
SCL HZ WILLGR 9-27-39-6 PARA WILLGR 9-25-39-6
YANGARRA HZ FERRIER 9-19-39-6
PARA HZ WILLGR 7-19-39-5
SCL HZ FERRIER 15-13-39-8
SCL 102 HZ FERRIER 16-13-39-8
T39
PARA HZ 103 MEDRIV 16-13-39-5
• Very active Duvernay area
within proven liquids
window
• Majors and Independents
are investing heavily in the
play
• Shell, Talisman, Black
Swan/Paramount are
executing multi-well
horizontal drilling programs
immediately adjacent to
YGR acreage
T39
TALISMAN 03 HZ WILLGR 14-9-39-6
PARA HZ 103 MEDRIV 8-12-39-5
TALISMAN HZ WILLGR 12-25-38-6
T38
Yangarra Resources Ltd
TALISMAN HZ WILLGR 8-24-38-6
TALISMAN HZ WILLGR 1-24-38-6
DUVERNAY SOUTH
Licensed to : Yangarra Resources Ltd
By :
Scale = 1:237500
TALISMAN HZ WILLGR 13-7-38-5
Date : 2014/09/18
Project : Duvernay (NAD83)
R9
TSX: YGR
T38
R8
R7
R6
R5
R4W5
22
R7
M
R6
R5W5
SCL HZ 102 FERRIER 4-21-40-7
SCL HZ FERRIER 3-21-40-7
T40
T40
PARA WILLGR 9-25-39-6
T39
T39
• Net Pay (YGR South
Block) ~36 m
• Southern Block is derisked by adjacent wells
• Continuous Duvernay
formation
Talisman 3-28-38-6W5
NUTECH WELL
TALISMAN HZ FERRIER 3-28-38-6
T38
T38
M'
HAN 14-9-38-9
R7
M
Shell Hz @ 3 -21 &
4-21-40-7W5
TSX: YGR
R6
R5W5
Yangarra South Block
Paramount Offset
Hz well at 08-19-39-5W5
(SL: 09-25-039-06W5)
Analogous
to 3-28
M’
23
• Vermillion/Black Swan and Sinopec/Daylight have drilled vertical
and horizontal test wells adjacent to YGR lands
TSX: YGR
24
15-18-49-13W5
7-4 - 49-12W5
7-3-47-11W5
100/15-18-049-13W5/00 <=13639.6m=> 100/07-04-049-12W5/00 <=22487.4m=> 100/07-03-047-11W5/00
Vermillion Strat Test
Vermillion HZ Offset
(1977)
at 10-28-48-12W5
Flowed 400 bbls
7-1-48-10W5
100/07-01-048-10W5/00
8-32-46-9W5
100/08-32-046-09W5/00
Sinopec HZ Producer
<=12376.5m=>
‘A
3100
3500
3100
3350
3350
A
<=16426.6m=>
?
?
3550
3150
3400
3400
11-22
3150
Dbvhl_lkB
Dbvrhl_lk
Dbvrhl_lk
Dbvrhl_lk
Approximate Hz well path
Dbvrhl_lk
Dbvrhl_lk
3450
15-18
Net Pay
A
7-4
Net Pay
Net Pay
10-28
Net Pay
7-1
7-3
TSX: YGR
8-32
A’
Net Pay
Duvernay Net Pay on YGR acreage
~20-24 m De-risking is underway
25
Appendix
TSX: YGR
26
Oil Hedges
2014: 1,200 bbl/d hedged at $95.02/bbl
2015: 1,100 bbl/d hedged at $93.65/bbl
Natural Gas Hedges
2014: 5,000 GJ/d hedged at $3.39/GJ or $4.20/mcf*
2015: 2,000 GJ/d hedged at $4.11/GJ or $5.10/mcf*
Interest Rate Swaps
4.70% Fixed rate on $10 million (June 2014-June 2018)
4.85% Fixed rate on $10 million (June 2014-June 2018)
* Assumes Yangarra specific heat value
TSX: YGR
27
YGR
PEY
BNP
BXE
WCP
BNE
TOU
RMP
2,606
55,636
74,309
36,342
30,575
10,744
5,203
13,911
109,953
12,437
Gas Weighting
50%
86%
67%
65%
29%
20%
39%
29%
85%
43%
Field Netback
$47.04
$33.69
$32.41
$29.25
$55.04
$51.20
$45.55
$55.85
$25.80
$45.87
Op Costs
$8.80
$3.83
$10.47
$8.72
$14.45
$13.06
$14.51
$14.13
$7.45
$7.24
Net Royalty
$3.66
$3.53
$11.06
$8.26
$10.29
$19.04
$8.97
$9.31
$3.14
$16.17
G&A Costs
$1.36
$0.12
$1.15
$1.39
$1.52
$2.01
$3.22
$2.66
$0.24
$1.64
Cash Flow
8.2
161.5
135.4
70.9
117.4
44.1
17.8
65.6
232
52.9
41.0
880
1,127
365
752
116
59.9
151.1
834
102
Debt/CF
1.3
1.4
2.1
1.3
1.6
0.7
0.8
0.6
0.9
0.5
Market Cap
200
10,371
2,814
1,483
4,068
986
399
2,016
10,371
4,069
EV
241
11,207
3,941
1,848
4,821
1,102
459
2,166
11,207
4,821
90,142
111,901
53,039
50,855
157,694
105,577
88,215
155,756
101,930
157,694
94%
148%
86%
88%
251%
157%
168%
208%
181%
205%
Current Share Price
$3.50
$34.78
$13.91
$7.60
$16.59
$11.10
$6.60
$62.95
$51.49
$8.30
NAV/ Share (Dec
31)
$4.20
$21.69
$17.21
$9.03
$4.96
$6.62
$3.53
$27.89
$26.58
$3.62
Cashflow Margin
59%
79%
47%
47%
53%
55%
55%
66%
63%
68%
PDP Change/CAPEX
1.27
$1.06
1.59
1.08
0.74
1.11
0.84
0.67
0.66
0.45
Cashflow Multiple
6.18
8.27
5.20
5.23
8.66
5.59
5.61
7.68
11.19
4.73
Production
Debt
EV/boe
EV/NPV10
TSX: YGR
DTX
TVE
28
$6,000
41% reduction in
average drilling costs
$5,000 since 2011
473
$4,000
498
1,807
$3,000
1,792
Drilling Represents 70%
of Corporate Costs
Staff count is down and
performance is up
373
1,376
Equip
273
Complete
Drill
1,134
$2,000
2,832
$1,000
2,134
2,088
1,563
$0
2010
TSX: YGR
2011
2012
2013
29
Second Quarter 2014 Production
2,606 boe /d
Liquid Content
Sales Price
51%
$
58.53 /boe
Royalty income
0.97 / boe
Royalty expense
(3.66) / boe
Production costs
(6.92 / boe
Transportation costs
Field Operating netback
(1.87) / boe
$
Commodity contract settlement
Operating netback
47.04 / boe
(8.81) / boe
$
38.23 / boe
G&A and other (excludes non-cash items)
(1.36) / boe
Finance expenses
(2.78) / boe
Cash flow netback
TSX: YGR
$
34.10 / boe
30
Statements in this presentation may contain forward-looking information including expectations of future production and
components of cash flow and earnings. Forward looking statements or information are based on current expectations,
estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially
from those anticipated by the Company and described in the forward looking statements or information. These risks and
uncertainties which may cause actual results to differ materially from the forward looking statements or information include,
among other things: general economic and business conditions; the risk of instability affecting the jurisdictions in which the
Company operates; the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and
producing crude oil and natural gas and market demand; the possibility that
government policies or laws may change or governmental approvals may be delayed or withheld; risks and uncertainties
involving geology of oil and natural gas deposits; the uncertainty of reserves estimates and reserves life; the ability of the
Company to add production and reserves through acquisition, development and exploration activities; the Company’s ability to
enter into or renew leases; potential delays or changes in plans with respect to exploration or development projects or capital
expenditures; the uncertainty of estimates and projections relating to production (including decline rates),
costs and expenses; fluctuations in oil and natural gas prices, foreign currency exchange rates and interest
rates; risks inherent in the Company’s marketing operations, including credit risk; health, safety and environmental risks; and
uncertainties as to the availability and cost of financing. Readers are cautioned that the foregoing list is not exhaustive of all
possible risks and uncertainties.
The reader is cautioned not to place undue reliance on this forward-looking information. The forward looking statements or
information contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update
publicly or revise any forward looking statements or information, whether as a result of new information, future events or
otherwise unless required by applicable securities laws. The forward looking statements or information contained in this
presentation are expressly qualified by this cautionary statement.
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31
Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil
(6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and
does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids
("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent
to one barrel of crude oil equivalent (Boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million
cubic feet of natural gas.
Reserve Definitions:
(a) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the
actual remaining quantities recovered will exceed the estimated proved reserves.
(b) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely
that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable
reserves.
(c) "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put
the reserves on production.
(d) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time
of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the
date of resumption of production must be known with reasonable certainty.
(e) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on
production, but are shut in, and the date of resumption of production is unknown.
(f) "Undeveloped" reserves are those reserves expected to be recovered from know accumulations where a significant expenditure
(for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully
meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.
(g) The Net Present Value (NPV) is based on Deloitte AJM Forecast Pricing and costs. The estimated NPV does not necessarily
represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the Deloitte AJM
evaluations will be attained, and variances could be material.
TSX: YGR
32
Yangarra Resources Ltd.
1530, 715 – 5 Ave. SW
Calgary, Alberta T2P 2X6
403-262-9558
TSX: YGR
33