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TSX-V: YGR www.yangarra.ca
March 2011
Corporate Presentation
Forward Looking Information
Statements in this presentation may contain forward-looking information including expectations of future production andcomponents 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 differmaterially from those anticipated by the Company and described in the forward looking statements or information. Theserisks and uncertainties which may cause actual results to differ materially from the forward looking statements orinformation include, among other things: general economic and business conditions; the risk of instability affecting thejurisdictions in which the Company operates; the risks of the oil and natural gas industry, such as operational risks inexploring for, developing and producing crude oil and natural gas and market demand; the possibility thatgovernment policies or laws may change or governmental approvals may be delayed or withheld; risks and uncertaintiesinvolving geology of oil and natural gas deposits; the uncertainty of reserves estimates and reserves life; the ability of theCompany to add production and reserves through acquisition, development and exploration activities; the Company’s abilityto enter into or renew leases; potential delays or changes in plans with respect to exploration or development projects orcapital expenditures; the uncertainty of estimates and projections relating to production (including decline rates),
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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 interestrates; 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 exhaustiveof all possible risks and uncertainties.
The reader is cautioned not to place undue reliance on this forward-looking information. The forward looking statements orinformation contained in this presentation are made as of the date hereof and the Company undertakes no obligation toupdate publicly or revise any forward looking statements or information, whether as a result of new information, futureevents or otherwise unless required by applicable securities laws. The forward looking statements or information containedin this presentation are expressly qualified by this cautionary statement.
Reserve Definitions
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 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 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 AJM evaluations will be attained, and variances could be material.
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Introducing Yangarra
Publicly listed junior oil and gas company TSX-V: YGR
Shares OutstandingBasicOptions/Warrants (Weighted avg. price $0.57)
103.8 million19.4 million
Fully Diluted 123.2 million
Management and Director OwnershipBasicFully Diluted
20%28%
Market Capitalization (Based on $0.75 share price) $78 million
Cash $4 million
Bank Debt ($14.5 million credit facility) Nil
Fourth Quarter 2010 average production Approx. 740 boe/d
CAPEX budget for 2011 $50.0 million
Proved plus Probable Reserves 5.1 million barrels
NPV10 (Proved plus Probable) $80.7 million
NAV/Share as at December 31, 2010 (basic) 1.00/share
Drilling Locations 123 Gross (70.2 Net)4
Management and Directors
Directors• Gordon Bowerman – Lead
DirectorFounder of several successful private and public oil and gas companies
• Arthur Dumont – Independent Director
Management/Officers• Jim Evaskevich – President & CEO
30 years extensive executive experience with strong operations background
• Dan Helman, P.Eng. - VP Exploitation28 years of diversified oil and gas engineering experience, including reservoir indepth evaluation and optimization
• Robert Weir- Independent Director
• Joseph Durante – Independent Director (MD of Toscana Capital)
• Jim Evaskevich – Director
• Jeff Dyck – Corporate SecretaryPartner Gowlings
optimization• Ron Gardiner, P.Geol. – VP Exploration
30 years experience exploring and developing oil and gas reservoirs, skills conducive to horizontal drilling
• James Glessing, CA – CFOExecutive and financial experience with North Peace Energy Corp, BlackRock Ventures and Deloitte
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Company Highlights
• $50 million drilling budget for 2011- 31 gross (13.7 net) wells
Significant 2011 Capital program
• Total of 123 gross (70.2 net) drilling locations
Expanding Drilling Inventory
• 15% gross S/S override on 11 sections of existing Glauconite
Significant Override in place
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• 15% gross S/S override on 11 sections of existing Glauconiteand Cardium lands in Willesden Green
• Net asset value as at December 31,2010 of $1.00/basic share
Strong Net Asset Value
• Liquids Rich Gas Stream significantly improve economics• $28.83/boe netback in the fourth quarter of 2010
High Netbacks
Company History
Date Event
Mar 1, 2010 Purchased 15% gross S/S override on 11 sections
Mar 10, 2010 $6 million equity raise ($0.375)
Mar 17, 2010 Drilled initial Yangarra Glauconite well
May 26, 2010 $2.1 million flow-through raise ($0.55)
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Jun 28, 2010 $1.9 million raise ($0.60 FT & $0.56 equity)
Oct 25, 2010 Willesden Green/Ferrier acquisition
Oct 28, 2010 $13 million raise ($0.75 FT & $0.65 equity)
Dec 21, 2010 $14.5 million credit facility in place
Mar 8, 2011 $17.25 million equity raise ($0.73)
Key Corporate Strategies
• Lower operating costs through
operational presence and cost efficiencies
• Maintain control over infrastructure
• Maximize netbacks with liquids rich targets
• Maintain flexibility in implementation of• Maintain flexibility in implementation of
new technology
• Continue to grow drilling inventory through drilling, geology and strategic acquisitions
• Focus within core multi-zone areas
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2010 Reserve Report Summary
• NPV10 Proved plus Probable of $80.7 million
• Increase of 113% from 2009
• Seaton-Jordan & Associates Ltd undeveloped land value of $10.4 million
• Proved plus Probable reserves of 5.054 million barrels
• Increase of 78% from 2009• Increase of 78% from 2009
• Replaced 2010 production by 723% on a Proved basis and 1379% on a Proved plus Probable basis
• Finding, development and acquisition costs on a proved plus probable basis were $11.73 per boe excluding changes in future development capital
• Net Asset Value of $79.9 million as at December 31, 2010, calculated to be $1.00 per basic common share
9Note: Reserve tables located in appendices
Pictures
Testing Yangarra’s firsthorizontal Glauconite well
6-3-41-7W5
Testing13-2-41-7W5
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Core Areas (Alberta, Canada)
Willesden Green / Ferrier
• Interest in 45+ Sections of land
• 28,000+ acres
• Multi-zone potential
• 10 horizontal wells drilled
• Focus area for 2011 capital budget
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Medicine Hat
Willesden Green/Ferrier
Jaslan
Edmonton
Calgary
Rocky Mountain House
Medicine Hat
• Interest in 123 sections of land
• 40+ producing wells
Jaslan
• Interest in 17+ sections of land
Multi Zone Potential
Cardium5m thick
Colorado Group650m thick
Second White Specks30m thick
Viking5m thick5m thick
Glauconitic20m thick
Ellerslie10m thick
Rock Creek15m thick
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Fracturing Technology
13
Rock Seal Ball
Port
Impact of Liquids-Rich Gas
$1.12
$1.60
$1.62
$6.00
$7.00
$8.00
$9.00
$10.00
$/m
cf
Condensate Value
Butane Value
Propane Value
Heating Value Adjust
Dry Gas
$8.98/mcf
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$0.64
$1.12
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
Glauconite
$/m
cf
$3.80/GJ
January 1, 2011 pricing on liquids
Drilling Summary
2010 DrillingLocation HZ Length Fracturing
Program
Working Interest (w.i.)
IP Length Production
06-03-41-7W5 Glauconite(operated)
710 m 8 stages 200 tonne
100% w.i. IP 30 602 boe/d
09-20-41-7W5 Cardium(non-operated)
699 m 5 stages 150 tonne
68.15% w.i. plus 15% override
IP 30 85 boe/d
07-20-41-7W5 Cardium(operated)
725 m 8 stages 200 tonne
68.15% w.i. plus 15% override
IP 30 324 boe/d
13-02-41-7W5 Glauconite 1,106 m 12 stages 68.15% w.i. IP 30 760 boe/d13-02-41-7W5 Glauconite(operated)
1,106 m 12 stages 300 tonne
68.15% w.i. plus 15% override
IP 30 760 boe/d
14-36-37-8W5 Cardium(operated)
550m 6 Stages
300 tonne
100% w.i. IP 30 50 boe/d on restricted production
1-20-41-7W5 Cardium(operated)
1,067m 12 Stages
240 tonne
68.15% w.i. plus 15% override
IP 30 285 boe/d
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2011 Drilling• 9.0 horizontal wells (4.0 net) drilled or drilling in Q1 2011
• 4.0 wells placed on-stream to date during 2011 (3.68 net) includes 2.0 standing horizontal wells drilled in 2010
• 7.0 wells (2.0 net) currently in various stages of drilling, completion or tie in
$50 million capital budget for 2011• 21 gross (11.1 net) operated wells
• 10 gross (2.6 net) non-operated wells
• $26 million spent in 2010 (92% increase in 2011)
• Capital allocated for infrastructure and land/asset purchases
2011 Budget Highlights
• Drilling in several different zones at Willesden Green/Ferrier
Credit Facility increased to $14.5 million (May 31st review)
• Credit facility combined with production revenue and recently announced equity financing will fully fund the 2011 capital budget
Strong Debt Ratios• Debt to equity ratio remains strong throughout 2011
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Glauconite - Willesden Green/Ferrier
• 25 km wide x 200 km long
• Sandstone very fine to fine grained with varying shale content
• Porosity: 3 – 12%
• Permeability: 0.01 - 1 md
Hoadley Glauconite Barrier Island Complex
6
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POROSITY TRENDS
T40
T41
T40
T41
R5W5R6R7R8
• Permeability: 0.01 - 1 md
• Horizontal drilling and multi-stage fracturing facilitated economic development in lower permeability areas
17
Yangarra Land Hoadley Glauconite Barrier Island ComplexFluvial Channels
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HOADLEY BARRIER
ISLAND COMPLEX
CHANNEL CUT
T37
T38
T39
T37
T38
T39
R5W5R6R7R8
Porosity Trends
15% Override Land
Glauconite - Willesden Green/Ferrier
Yangarra Land
HoadleyGlauconiteBarrier Island Complex
3D Seismic
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O
GLAUCONITIC PRODUCING WELLS IN RED
6-2-41-7 U.SAND HAS 7-8% POROSITY AND 0.1 TO 0.5 md
PERMEABILITY IN CORE . L. SAND 10-12%POROSITY,0.2 TO
0.6 md
10-35-40-7 HAS CUMULATIVE PRODUCTION OF 745 MMCF GAS.
LOGS SHOW 5 METERS > 6% POROSITY WITH AN 11% STREAK
YANGARRA'S FIRST HORIZONTAL GLAUCONITIC WELL AT 6-3-41-7. IP30 602 BOE/d
T41T41
R6W5R7R8
32 locations
(13.2 net)
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123456
7 8 9 10 11 12
131415161718
19 20 21 22 23 24
252627282930
31 32 33 34 35 36
123
10 11 12
131415
22 23 24
252627
34 35 36
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10-34-40-7 CLEAN SAND WITH HIGH
RESISTIVITY. HOLE WASHED OUT .
ESTIMATE FROM SP AND GR 12.4 METERS
OF POROUS SAND. PRODUCES 70 MCF/D
AND 2 BBLS/D OIL
POROSITY WITH AN 11% STREAK
YANGARRA 13-19 WELL
HAS 11 METERS OF 9-10% POROSITY ON LOGS
11-21 WELL HAS 14m PAY > 6%
POROSITY. CUMULATIVE
PRODUCTION OF 32 MMCF
RECENT BONAVISTA GLAUC
HORIZONTAL. FLOWING
GAS AT RESTRICTED RATE.
3D SEISMIC
FERRIER/WILLESDEN GREEN
GLAUCONITIC SAND TREND
T40T40
R6W5R7R8
18
(13.2 net)
15% Override
on 11 sections
Access to
facilities
Glauconite – Generic Type Curves & Economics
19Note: Taken from Bonavista Energy Trust’s corporate presentation
3131 3631 3631 3631 3631 3636
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LOWER
CARDIUM
UPPER
CARDIUM
Harvest 9-20 IP30 85 BOPD
Bellatrix 13-19IP38 412 BOPD IP180 107 BOPD
Yangarra 1-20recent drill
Yangarra 7-20 IP30 324 BOPD
T41
T42
T43
T41
T42
T43
R4W5R5R6R7R8R9R10
Cardium - Willesden Green/Ferrier
• 29 locations (12.6 net)
• 15 % override on 12 locations
• Extent of upper and lower Cardium >6% porosity
Willesden Green
3131 3631 3631 3631 3631 3636
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F
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29 gross potential
horizontal locations
WILLESDEN GREEN-FERRIER
EXTENT OF PROSPECTIVE AREAS
Only Cardium producing wells plotted
1.5
ABS
western edge of Cardium A sand
Yangarra 14-36
Angle 16-27, 3rd month prod 1267mcf/d,222 bbls oil/d
K
T37
T38
T39
T40
T37
T38
T39
T40
R4W5R5R6R7R8R9R10
20
porosity
Yangarra Land
Upper Cardium
Lower Cardium
Cardium Oil
Ferrier
Cardium – Generic Type Curves & Economics
21Note: Taken from Bonavista Energy Trust’s corporate presentation
Summary
• Multi zone potential in the Willesden Green/Ferrier area
• Significant 2011 Capital program
• Expanding Drilling Inventory
• Significant Override in place
• Strong net asset value
• High Netbacks due to liquids-rich gas
22
Appendix
Reserve Tables
24
Reserve Tables
25
Finding and Development Costs
26
Net Asset Value
27
Glauconite Well Analogy00/06-02-041-07W5/0
RR: 1980-01-27
FormTD: PEKISKO
Fluid: N/APOCO ET AL WILLGR 6-2-41-7Mode: Abnd
ProdForm:
KB: 1032.5 m
20665.0m to next well >
2450.00
G L AUC S S2 4 70. 5 (- 14 38. 0) [ TV D] < S >
C O AL
2 4 49. 9 (- 14 17. 4) [ TV D] < U >
2450.00
GL AU CS S24 70 . 5 (- 14 38 . 0) [ TV D ] <S >
CO AL
24 49 . 9 (- 14 17 . 4) [ TV D ] <U >
00/12-26-041-05W5/0RR: 1979-09-15
FormTD: BANFF
Fluid: GasAMOCO WILLGR 12-26-41-5
Mode: Pump
ProdForm: COLRAD,CARDSD
KB: 987.3 m
< 20665.0m to previous well
2170.00
CO AL
21 72. 7 (- 11 85. 4) [ TV D] < U >
GL AUC S S
21 90. 2 (- 12 02. 9) [ TV D] < U >
2170.00
CO AL
21 72 . 7 (- 1 1 8 5. 4 ) [ T V D ] <U >
GL AU CS S
21 90 . 2 (- 1 2 0 2. 9 ) [ T V D ] <U >
Diamond, conventionalCEMENT PLUG
2450
(-1417.5)
2475(-1442.5)
Diamond, conventional
2175(-1187.7)
2200
6% porosity
Upper Glauconitic
6% porosity
100500
28
2500.00
OS TCZ
2 4 92. 8 (- 14 60. 3) [ TV D] < U >
G L AUC S S LW R
2 4 84. 0 (- 14 51. 5) [ TV D] < U >
2500.00
OS TC Z
24 92 . 8 (- 14 60 . 3) [ TV D ] <U >
GL AU CS S L WR
24 84 . 0 (- 14 51 . 5) [ TV D ] <U >
2220.00
OS TCZ22 08. 8 (- 12 21. 5) [ TV D] < U >
GL AUC S S LW R
22 00. 9 (- 12 13. 6) [ TV D] < U >
2220.00
OS TC Z22 08 . 8 (- 1 2 2 1. 5 ) [ T V D ] <U >
GL AU CS S LW R
22 00 . 9 (- 1 2 1 3. 6 ) [ T V D ] <U >
Diamond, conventional
(-1442.5)
2500(-1467.5)
2200(-1212.7)
Lower Glauconitic
Base of Glauconitic
• The 6 - 2 well which offsets Yangarra’s 6 - 3 horizontal well shows 7 - 8% porosity and up to 0.5 mdpermeability in the upper sand
• Yangarra’s 6 - 3 well showed 6 - 9% porosity throughout the horizontal section with streaks of 12% porosity in the lower sand
• The 12 - 26 well offsets Bonavista’s 02/01-27-41-5W5 well that had a three month IP of 2.8 mmcf/d. Porosity is 6 - 8% on logs and core in the upper sand. Permeability is 0.05 md to 0.2 md in the upper sand
Cardium Well Analogy
00/13-20-041-07W5/2RR: 2006-06-17
FormTD: NORD
Fluid: OilBIRCHILL WILLGR 13-20-41-7Mode: Pump
ProdForm: CARDSD
KB: 972.5 m
76653.4m to next well >
1970.00
CAR DSD19 7 1.3 (-9 98 .8 ) [T VD] < U >
CAR DSD M ID19 7 7.0 (-1 00 4. 5) [TVD] < U>
1970.00
CAR DSD1 97 1 .3 ( -9 98 .8 ) [T VD] <U >
CAR DSD M ID1 97 7 .0 ( -1 00 4.5 ) [ TVD] < U>
00/12-29-047-02W5/0RR: 2000-08-18
FormTD: ELLERSL
Fluid: N/AEXORO ENERGY PEMBINA 12-29-47-2Mode: Abd & Re
ProdForm:
KB: 912.6 m
< 76653.4m to previous well
1310.00
CAR DSD
1 31 8.6 (-4 0 6.0 ) [T VD] <U >
CAR DSD M ID1 32 2.3 (-4 0 9.7 ) [T VD] <U >
1310.00
CAR DSD
1 31 8 .6 ( -4 06.0 ) [T VD] <U >
CAR DSD M ID1 32 2 .3 ( -4 09.7 ) [T VD] <U >
JET PERFORATION
FRACTURED
1960(-987.5)
1970(-997.5)
1980
1310(-397.4)
1320(-407.4)
6%porosity6% porosity
UPPER CARDIUM
LOWER CARDIUM
1990.00
BL A CKSTN19 8 5.7 (-1 01 3. 2) [TVD] < U>
1990.00
BLA CKSTN1 98 5 .7 ( -1 01 3.2 ) [ TVD] < U>
1340.00
BLA CKSTN1 32 9.8 (-4 1 7.2 ) [T VD] <U >
1340.00
BLA CKSTN1 32 9 .8 ( -4 17.2 ) [T VD] <U >
1980(-1007.5)
1990(-1017.5)
1330(-417.4)
1340
(-427.4)
CARDIUM
BASE OF LOWER CARDIUM
CARDIUM WELL ANALOGY
This vertical well offsets the best east Pembina horizontal producer, Bonterra 8-30-47-2, which had an average 3 month oil IP of 317 BOPD and is currently 227 BOPD. The upper sand appears to be conglomeratic, based on the low density reading. It likely has porosity in the 12-15% range and good permeability in the 50 to 100md range.
Yangarra interest vertical well which had an average 3 month oil IP of 60 BOPD. Thiswell was completed in the upper sand onlywhich has log porosity of 15-16% and should have permeability in the 40-50 md range.
29
• The cross section compares the Yangarra 13-20-41-7W5 vertical well (IP 60 boe/d cum 25,000 bbls, current 24 bopd) with the East Pembina 12-29-47-2W5 vertical well that offsets the Bonterra 8-30-47-2W5 horizontal well
• The Bonterra well had a first three month average daily production of 317 bopd
• The porosity, cleanliness and thickness of the upper sand are very similar to Yangarra’s 13 - 20 well
• The lower sand in the 13 - 20 well will contribute further production
29
Cardium Well Analogy – Section 36-37-8W500/10-36-037-08W5/0
RR: 1980-09-25
FormTD: CARD UPPER
Fluid: OilGRIFFON FERRIER 10-36-37-8Mode: Flow
TD: 2358.0 m [TVD]
KB: 1070.7 m
8655.4m to next well >
00/16-35-037-07W5/0RR: 2006-01-11
FormTD: BLACKSTN
Fluid: OilCREW FERRIER 16-35-37-7
Mode: Pump
TD: 2255.0 m [TVD]
KB: 1027.0 m
< 8655.4m to previous well
2300.00
CARD2306.8 (-1236.1) [TVD] <U>
CARD UPPER2321.0 (-1250.3) [TVD] <U>
CARD BASE2327.6 (-1256.9) [TVD] <U>
2300.00
CARD2306.8 (-1236.1) [TVD] <U>
CARD UPPER2321.0 (-1250.3) [TVD] <U>
CARD BASE2327.6 (-1256.9) [TVD] <U>
2160.00
CARD2160.0 (-1133.0) [TVD] <S>
CARD UPPER2172.0 (-1145.0) [TVD] <S>
CARD BASE2179.3 (-1152.3) [TVD] <U>
2160.00
CARD2160.0 (-1133.0) [TVD] <S>
CARD UPPER2172.0 (-1145.0) [TVD] <S>
CARD BASE2179.3 (-1152.3) [TVD] <U>
Diamond, conventional
JET PERFORATION
FRACTURED
1
2300
(-1229.3)
2325(-1254.3)
JET PERFORATION
FRACTUREDJET PERFORATION
2150(-1123.0)
2175(-1148.0)
3030
BLACKSTN2340.2 (-1269.5) [TVD] <U>
BLACKSTN2340.2 (-1269.5) [TVD] <U>
2210.00
BLACKSTN2193.0 (-1166.0) [TVD] <S>
2210.00
BLACKSTN2193.0 (-1166.0) [TVD] <S>
2350(-1279.3)
2200(-1173.0)
Logs show 2m of 12-14% and 1m at 9% porosity.
Well has produced 32 MSTB and 107 MMcf of gas.
Producing 6 bopd when shut in due to pump
failure. SP permeability looks better than 16-35.
This well offsets recent Angle horizontal wells,
one of which is reported to be producing at
250 bopd and 3 MMcf/d (unsubstantiated).
Logs exhibit 1m at 16%, 1m at 14% and
3m at 9% porosity. Well has produced 7 MSTB
and 74 MMcf of gas.
Medicine Hat
• 90 sections:
− 100% working interest
• 4.0 mmcf/d plant:
− 100% ownership
• Current production:
− 800 mcf/d from vertical wells
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Yangarra Land Yangarra Wells
Jaslan
• Six sections
− 37.5% working interest
− Five wells drilled at 37.5%
• 15 sections
− 100% working interest
− Five wells drilled at 100%
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• 2.9 Mmcf/d compressor station
− 45% ownership
• 100% gas production
• Three Wabamun pools to develop
• Mannville secondary targets present
• 1.5 Mmcf/d current production
Yangarra Land Yangarra Wells
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Contact Information
Yangarra Resources Ltd.
1530, 715 – 5 Ave. SW
Calgary, Alberta T2P 2X6
403-262-9558
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