1. Underground Energy Corp.
Unlocking Shale Oil Opportunities in California & Nevada
TSX-V:UGE
OTCQX:UGGYF
GHS Energy Conference Corporate Presentation
June 2012

2. Capital Structure Snapshot
UGE $0.17
Listed on the TSX Venture Exchange June 20, 2012 Closing Share Price
204.9 million $34.8 million
Basic Shares Issued and Outstanding Market Capitalization (on Basic Shares)
339.4 million $11.2 million
Fully Diluted Shares Outstanding Cash Balance at March 31, 2012
16.7% $25.6 million
Insider Ownership Working Capital at March 31, 2012
24.1% $23.6 million
Institutional Ownership Enterprise Value (on Basic Shares)
59.2% $39.2 million
Retail Ownership Potential Proceeds from Dilutive Securities
 59 million warrants at 21.7 cents – expires 09/13
 52 million warrants at 40.5 - 43.4 cents – expires 08/13
2

3. California Focused Operations
 Discovery of new Monterey play type in
Santa Maria Basin
CALIFORNIA • Basin has produced over 2 billion bbls oil
 Impressive oil shows in initial wells at Zaca
Extension Project – production testing
underway
NEVADA
San Francisco  Substantial build out potential at Zaca
• Over 120 well locations identified based on
seismic / well control
Las Vegas
 Outstanding economics – Monterey has best
shale oil net backs in North America
 Inventory of permitted well sites continues to
Los Angeles grow, > 40 permitted wells in California
Zaca
 Critical Mass achieved at Zaca and across
core prospect areas – 73,617 net acres
Underground leases
3

4. Complete California Based Team
 Experienced, California-based technical and operations team assembled
• In excess of 200 years combined experience in California, proven ability to grow reserves and production in California
• Track record of building successful E&P companies – Management and Directors include founders of OSUM Oil Sands
Management Team
 Michael Kobler – Founder, Chairman, President and CEO
 Bruce Berwager – Chief Operating Officer
 Peter Ballachey – Founder, CFO and Corporate Secretary
 Simon Clarke – VP Corporate Development
 Dana Brock – VP Engineering
 David Hoyt – VP Exploration and Development
 Randy Ray – Chief Geophysicist
 Peter Bacon – Manager of Land
Board of Directors
 Michael Kobler – Chairman
 Randy Aldridge – Koch Oil Co., True Energy
 Harland Johnson – ExxonMobil
 Andrew Squires – OSUM Oil Sands, PetroCanada, Amoco
 Douglas Urch – Bankers Petroleum, Rally Energy
Note: Refer to the Appendix for detailed description of the Company's management team and board of directors 4

5. History of Value Creation
Discovered New Play
Built land position in Santa Maria Basin
to ~80,000 net
Permit for initial acres in
Focus on 26 wells California and Impressive oil
permitting granted Nevada shows in initial wells
process at Zaca
Rounded out
Initial Added senior
Company Monterey California management IPO and raised Target exit Production
Inception Lease expertise team $25.5 million 450+ bbls/day
2007 2008 2009 2010 2011 2012
5

6. California’s Petroleum Basins
Oil and Gas Fields in California
 2nd largest onshore US oil producing state
• 5 of 10 largest fields in US
 2010 production 740,000 boe/d
• 100% consumed in State
Sacramento Basin
 36 Billion BOE produced to date
Total oil refining
capacity in State  Fully-integrated heavy oil infrastructure
San Francisco is 2 million bopd
 Very robust oil price environment
San Joaquin Basin  54,000 producing wells in 2011
 California’s refinery oil sources in 2011:
California
Bakersfield 16%
Alaska
Santa Maria Basin 8% 37%
Saudi Arabia
Ventura & Santa Barbara
Zaca 11% Ecuador
Channel
Iraq
Santa Barbara Los Angeles Basin
15% 13% Other
Pacific Ocean Los Angeles
Source of slide stats: California DOGGR (2001), US Department of Interior Bureau of Land Management 6

7. Monterey Shale Formation
Significant Monterey Shale Basins
World Class Source Rock
Over 290 billion barrels of oil generated1
World Class Reservoir Rock
San Joaquin Basin
Produced over 2.5 billion barrels1
High organic content of 4-5%
Extremely thick shale packages of 500-3,500 ft
Compared to other US shale plays:
Bakken: 20-150 ft,
Eagle Ford: 75-300 ft,
Santa Maria Basin Niobrara: >150 ft
Monterey players include:
Ventura & Santa Barbara Channel Los Angeles
Underground Monterey prospects
Los Angeles Basin
1. Source: California DOGGR and USGS 7

8. California: Premier Oil Price in North America
California (CA) MWSS begins $120.00
trading at a
 CA imports 62% of crude oil (~ 1 MM bopd) by sea premium to WTI
(Alaska, Saudi Arabia, Ecuador, Iraq, Columbia, Brazil, Angola, $110.00
Russia, Oman, Venezuela, Argentina, Peru, & Australia)
$102.96
 CA is not connected to other US oil supply or markets $100.00
 CA oil prices currently more reflective of world prices
(e.g. Brent) than WTI
$90.00
 Rig availability with low servicing costs and year–round access
to CA projects
$80.00
$70.00
$60.00
$50.00
$40.00
WTI West Texas Intermediate- 39.6 API
MWSS Midway Sunset- 13.0 API
$30.00
WCS Western Canada Select- 20.6 API
$20.00
May-09 May-10 May-11 May-12
8

9. US Oil Play Comparison
Monterey Shale is largest shale oil formation in the US
 Estimated 15.4 billion bbls of recoverable oil
 2/3 of total US shale oil potential
Technically
Well Cost EUR/well IP Rate Well Cost/EUR IRR (%)
Play Recoverable
($US MM) (MBbl) (BOPD) ($/BO) @$85 WTI
(BBO)1
California Monterey (SMV) 15.4 $2.0-2.5 375-550 200-300 $4.50-5.50 120%
Louisiana Tuscaloosa N/A $12.0-14.0 400-600 700-900 $23-30 N/A
Colorado Niobrara N/A $4.7-5.2 200-300 250-300 $17-24 N/A
Ohio Utica N/A $3.0-5.0 200-300 200-250 $15-17 80%
Texas Wolfberry N/A $1.8-2.0 120-170 100-125 $12-15 45%
Texas Avalon/Bone Springs 1.6 $5.5-6.0 330-550 500-550 $11-16 82%
N. Dakota/Montana Bakken 3.6 $7.0-9.0 500-600 500-900 $10-14 90%
Texas Eagle Ford Oil 3.4 $4.0-6.5 250-350 500-600 $8-11 90%
Oklahoma Mississippian Lime N/A $3.0-3.5 300-400 275-325 $8.50-10 100%
1. Sources: US EIA Review of Emerging Resources: US Shale Gas and Shale Oil Plays dated July 2011, Devon’s Analyst Day Presentation
dated April 4, 2012, and actual costs of Underground Energy, Inc. 9

10. Santa Maria Basin / Greater Zaca Area
 2010 oil production of 25 million bbls Foxen Canyon Trend
 69,000 bopd in 2010 (onshore 9,400/ offshore 59,600)
 935 producing wells
 Approximately 2 billion bbls oil produced to date1 To Los Angeles
Santa Maria
Santa Barbara County
Conoco Phillips
207
To San Francisco Santa Maria Refinery All American Pipeline
Greka/Santa Maria
Asphalt Refinery All American Pipeline Cat
Canyon
251
Orcutt
Pacific
209
Ocean Asphaltea
PXP/Lompoc
101
Oil & Gas Plant
Santa Barbara Gato Ridge
County 54
Barham Zaca
Los Alamos
Ranch
To Los Angeles 35
Santa Rita
Monterey Oil Field Oil and Gas separation,
Treatment and Gas Lompoc 52
Processing Plant
Underground Leases
Pipeline Refinery 3 miles
Estimated Ultimate Oil Recoveries (MMBO)
1. Source: California DOGGR, BOEMRE and GLJ Petroleum Consultants 10

11. Zaca Field Development Project
As Acquired by UGE
 61 wells drilled to date at Zaca
 Recovery to date of 32 MMbbls
• 6.8% of OOIP
• Primary recovery only
 UGE acquired 6,200 net acres at
Zaca Field Extension for lower risk
step out wells
 Initial Management Estimates1:
• 6 MMbbls 2P Reserves
• 20.8 MMbbls Prospective
Resources
 GLJ Reserve Estimates2:
• 1.8 MMbbls 2P / 3.6 MMbbls 3P
• 2P NPV10 BT – approx. $35.4 M
 Increased Recovery potential from
• Enhanced seismic Existing Oil Well
Underground Energy Lease Boundary
• Deviated/horizontal drilling Zaca Oil Field Recognized Boundary
• EOR schemes Existing Zaca Field
• Thermal testing (1964-1967) Existing Seismic Line circa 1986
• Waterflooding (1953-1954
1. Management estimates which also include review by an internal qualified reservoir engineer
2. GLJ reserve estimates as at 31 December, 2011 from report dated 10 April, 2012 11

12. Zaca Field Extension Project
Achievements to Date
3,943 Total Acres
 New Fault Block discovered Seismically
Defined 2,121 acres
 Upper and lower productive zones
acquired May
2012
identified by seismic and drilling
46 acres
 Initial wells have encountered
significant quality oil shows 159 acres
• Chamberlin 3-2 had a total of
1,700 feet of quality oil shows in
two Monterey sections 218 acres
 Land base increased to 12,183 net
935 acres
acres and 96.7% WI acquired May
2012
627 acres 218 acres
 Acquired minority interests in play
 Added additional leases 774 acres
Existing Oil Well
Underground Energy Original Lease Boundary
 13 drilling locations permitted Underground Energy Acreage Additions 1,901 acres
Zaca Oil Field Recognized Boundary 1,213 acres
acquired May
Existing Zaca Field 2012
Probable Geologic Structure Identified by Seismic 385 acres
acquired May
Possible Geologic Structure Identified by Seismic 2012
Existing Seismic Line circa 1986
New UGE Seismic Lines
Permitted Pad Locations 0 3213
UGE Well Already Drilled
Permitted Well Location feet
12

13. Zaca Field Extension Project
Go-Forward Strategy
3,943 Total Acres
 4 wells planned to be drilled by Seismically
year-end on current budget Defined
 Targeting 450+ bopd by year-end
46 acres
 Re-process / shoot new seismic on
West Side of lease / new lands 159 acres
 Continue to permit within field and 218 acres
extend field boundary (~ 1 year)
• 2 new well pads / 10 additional
wells in process
627 acres 218 acres
 Full Development of East Side: 774 acres
• 60+ wells within existing field Existing Oil Well
• 60+ wells outside existing field Underground Energy Lease Boundary
1,901 acres
Zaca Oil Field Recognized Boundary
• Currently identified structures only Existing Zaca Field
Probable Geologic Structure Identified by Seismic
Probable Geologic Structure Identified by Seismic
Possible Geologic Structure Identified by Seismic
 West side / new lands offer Existing Seismic Line circa 1986
New UGE Seismic Lines
significant additional potential Permitted Pad Locations
Being Permitted Pad Locations
UGE Well Already Drilled 0 3213
Permitted/Being Permitted Well Location
Potential Well Site feet
13

14. Zaca Field Seismically Defined Structures
UGE Chamberlin 3-2
UGE Chamberlin
Well
3-2 Well
Original Zaca Field
Original Zaca
Block Block
Field
North East
Structure
Hathaway 1 Well North
South East Structure
S-11 Structure
Structure
S-10
Structure
Oil Shows
Upper Thrust
Lower Thrust
14

15. Zaca Field Magnetics and Anomalies
UGE Chamberlin 3-2, 4-2 & 5-2
Residual Magnetics
Current UGE Well
Locations
Proposed UGE Wells
Previous Productive
Wells
UGE Leaseholds
UGE Chamberlin 1-2 & 2-2 State of CA Oil Field
Boundary
15

16. Zaca Idealized Cross Sections and Well
Penetrations
1.5 Mile
Hathaway 1 Carranza 22 Chamberlin
Potreros 14 Carranza 21 5-2, 3-2, 4-2
Sub-Thrust Block
Basement
16

17. Zaca / Monterey Shale Type Curves
1. Source: Occidental Petroleum Corporation, Minerals Management Service, DOGGR 17

18. Zaca Economics & Development Program
Typical Well All Wells Infill Wells Zaca Resource Initial Build Extended Build
Type Curve Type Curve Upside Potential Out Profile Out Profile
Well Depth (MD feet) 5,500-8,500 4,000-5,500 Locations 60 120
Dry Hole Well Costs ($M) $1,500-$2,200 $1,200-$1,800 UGE WI% 96.7% 96.7%
Completion Cost ($M) $300-$550 $200-$400 D,C&T Costs Per Well $2.2 $2.2
($MM)
Total Well Cost ($M) $2,400 $1,900
Base Case IP Rate 160 160
UGE Interest (WI / NRI) 96.7% / 75.6% 96.7% / 75.6% (bbls/d)
Reserves per Well 503.7 503.7
1st Month IP Rate (BOPD) 205 70 (Mbbls)
Cum. Production (MBO) 537 375 NPV per Well @10% BT $12.2 $12.2
($MM) 1
NPV @10% BT ($M)1 $ 11,023 $ 4,296 UGE WI Program NPV $708.0 $708.0
@10% BT ($MM)1
IRR (%) 110% 51% Added Value ($MM) $708 $1,416
Payback (years) 0.8 1.8
1. Economics are internal estimates using NYMEX Futures Strip Prices as of May 31, 2012 with adjustment for location and gravity
18

19. Zaca Sensitivity to Various Oil Prices
$12,000 120%
$10,000 100%
$8,000 80%
Internal Rate of Return (%)
$6,000 60%
Net Present Value (BT) at 10% DCR ($M)
$4,000 40%
$2,000 20%
$- 0%
$90.00 $80.00 $70.00 $60.00 $50.00 $45.00 $40.00
WTI Oil Price at Cushing, OK
19

20. Other California Assets – Santa Maria
Asphaltea
San Francisco 10 0 10 20 30 40 50 miles
 High impact exploration project
Modesto
Merced  5,850 acres (100% WI – operated) in Santa
County
Stanislaus Barbara County, California
County San Joaquin Basin  Analog fields: Zaca (32 MMboe), Cat Canyon (251
Madera
County Mmboe), Orcutt (209 Mmboe)
Fresno
County
 Work at Zaca transferable to Asphaltea
San Benito Fresno
 2 potential structures identified – naturally
County fractured
 26 permitted wells
Tulare
 30+ miles of 2D swath seismic acquired 2011
Kings
Pacific County
County currently being processed
Ocean  2 billion bbls OOIP / 109 MMbbls Prospective
Resources1
Petroleum Basin
Producing Oil Field Santa Rita
Producing Gas Field
San Luis Obispo
 Santa Barbara County, California
Underground Property Bakersfield
Highlighted Property
County
 80% WI (Operator), 1,217 gross acres (974 net
acres)
Kern
Santa Maria Basin County  Monterey Shale & Point Sal sand oil targets
 On trend with Lompoc Field (52 MMbbls)
Asphaltea
Santa Rita Zaca Santa Barbara
County
Santa Barbara
1. Source: GLJ Petroleum Consultants, effective date June 1, 2011 20

21. Other California Assets – San Joaquin
Devil’s Den
San Francisco 10 0 10 20 30 40 50 miles  Kern County, California
Modesto
Merced
 98.2% WI (Operator), 5,341 gross acres (5,246 net acres)
County  Shallow Monterey (Diatomite) and Tumey shale oil targets
Stanislaus
County San Joaquin Basin  Existing 3D sesimic
Madera
 Analog fields: McKittrick (350 MMboe), Cymric (543 MMboe)
County Burrel
Challenger Fresno  Fresno County, California
County
 88.2% WI, 8,973 gross acres (7,911 net acres)
San Benito Fresno
County  Zilch & Vaqueros sand, Monterey & Kreyenhagen oil targets
 1 producing well (35 bopd)
Burrel
 Existing 2D seismic
Kings
Tulare  265,000 bbls 2P Reserves / 561,000 bbls 3P Reserves1
Pacific County
County
 Analog fields: Helm (46 MMboe), Raisin City (47 Mmboe)
Ocean Buttonwillow
 Kern County, California
Petroleum Basin  93.3% WI (Operator), 1,445 gross acres (1,349 net acres)
Producing Oil Field Devil’s Den Buttonwillow  Monterey/McClure shale, 44X and Randolph sand oil targets
Producing Gas Field  In middle of Oxy/Venoco 3D seismic survey
Underground Property San Luis Obispo
County Bakersfield  Offset well planned by Venoco
Highlighted Property  Analog fields: North Shafter (10 MMboe), Rose (4.8 MMboe)
Challenger
Kern
Santa Maria Basin County  Madera and Merced Counties, California
Asphaltea
 70.5% WI (Operator), 7,585 gross acres (5,347 net acres)
Santa Rita Zaca Santa Barbara
 32 miles existing 3D seismic
County  Zilch, Blewett, Vaqueros/Temblor sands; and Kreyenhagen
Santa Barbara & Moreno shale gas targets
1. Source: GLJ Petroleum Consultants, effective date December 31, 2011 21
21

22. Nevada Assets
 “Early mover” advantage by building a strong
Bull Run land position ahead of the curve
Deadman
Winnemucca Elko Creek
 Complex geology, but existing conventional
discoveries have had very high production rates
Blackburn
West
 Emerging shale oil potential (Bakken-like)
Reno
RAILROAD VALLEY
46.2MMBO
Trap
 UGE has 31,286 net acres in 6 prospective
Springs Flat Top areas – history of production / oil shows
Coaldale
 Noble Energy recently acquired Elko county
acreage for $50 per acre & began 3D seismic
 Key competitors will help prove up plays -
Las Cabot (COG), EOG (EOG), SM Energy (SM),
Vegas
Callon (CPE), PetroHunt
Underground leases
22

23. Initial Exploration and Development Plan
Activity 1Q12 2Q12 3Q12 4Q12 Net Cost ($MM)
Acquire & Process Seismic $0.2
(30 mi 2D)
Drill 4 Monterey Shale Wells $10.0
Zaca
Design & Build Facilities and additional $2.0
optimization work
Permit Additional Drill Sites & Increase $0.2
Acreage
Acquire & Process Seismic at Devil’s $0.2
Den (50 mi 2D) & Prepare to Drill
Other Acquire Seismic at Buttonwillow (16 mi $0.2
CA 3D, 30 mi 2D) & Prepare to Drill
activity
Continue Leasing at MVA. Reprocess $0.2
3D Seismic & Prepare to Drill
$13.0
Seismic Drilling Other
23

24. Initial Development Profile
Zaca Project Initial Development Profile 2012
Key Assumptions
600 $3,330,861 $3,500,000
 4 producing wells in 2012 (current budget only)
 IP per well = 153 bopd
 Primary recovery only $3,000,000
500
452
Cumulative Operating Cash Flow ($USMM)
Exit production 452 bopd / annualized net
cash flow of $7.04 million $2,500,000
Daily Gross Production (bopd)
400
$2,000,000
300
$1,500,000
200
$1,000,000
100
$500,000
0
0 $0
May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12
Month
Bopd Cumulative Operating Cash Flow
1. Economics are based on management estimates of production post-royalty and based on May 31, 2012 NYMEX Futures strip prices 24

25. Contact Information
Underground Energy Corp. President & CEO – Mike Kobler
3rd Floor mike.kobler@ugenergy.com
7 W. Figueroa Street Phone: (805) 845-4700, x18
Santa Barbara, CA,
93101-5109 CFO – Peter Ballachey
peter.ballachey@ugenergy.com
Tel: 805-845-4700
Phone: (805) 845-4700, x17
Fax: 805-845-1177
www.ugenergy.com COO – Bruce Berwager
bruce.berwager@ugenergy.com
Phone: (805) 845-4700, x11
VP Corp Development – Simon Clarke
simon.clarke@ugenergy.com
Phone: (604) 551-9665
25

26. Cautionary and Forward Looking Statements Advisory
Underground Energy Corp. (Underground Energy) is a British Virgin Island holding company that owns Underground Energy, Inc., a Delaware corporation which is
an exploration and production company focused on unlocking oil from shale plays, principally in the Western US. Underground Energy is traded on the TSX
Venture Exchange under the trading symbol "UGE.“
Statements in this presentation contain forward-looking information and forward-looking statements within the meaning of applicable securities laws (collectively,
"forward-looking information"). Forward-looking information is frequently characterized by words such as "plan", "expect", "project", "intend", "believe", "anticipate",
"estimate" and other similar words, or statements that certain events or conditions "may" or "will" occur. In particular, forward-looking information in this
presentation includes, without limitation, statements with respect to: (i) the closing and closing date of the Company's proposed acquisition of oil and gas leases in
California; (ii) the Company's planned seismic operations to be conducted on such oil and gas leases; and (iii) the prospectivity of such oil and gas leases for oil
and gas and the anticipated drilling, completion and production results therefrom. Readers are cautioned that assumptions used in the preparation of forward-
looking information may prove to be incorrect.
Although we believe that the expectations and assumptions reflected in the forward-looking information are reasonable, there can be no assurance that such
expectations or assumptions will prove to be correct. In particular, assumptions have been made that: (i) Underground will be able to obtain equipment and
regulatory approvals in a timely manner to carry out exploration and development activities; (ii) Underground will have sufficient financial resources with which to
conduct its planned capital expenditures; and (iii) the current tax and regulatory regime will remain substantially unchanged. Certain or all of the forgoing
assumptions may prove to be untrue.
Forward-looking information is based on the opinions and estimates of management at the date the statements are made, and is subject to a variety of risks and
uncertainties and other factors (many of which are beyond the control of Underground) that could cause actual events or results to differ materially from those
anticipated in the forward-looking information. Some of the risks and other factors could cause results to differ materially from those expressed in the forward-
looking information include, but are not limited to: operational risks in exploration, development and production; delays or changes in plans; competition for and/or
inability to retain drilling rigs and other services; competition for, among other things, capital, acquisitions of reserves, undeveloped lands, skilled personnel and
supplies; risks associated to the uncertainty of reserve and resource estimates; governmental regulation of the oil and gas industry, including environmental
regulation; geological, technical, drilling and processing problems and other difficulties in producing reserves; the uncertainty of estimates and projections of
production, costs and expenses; unanticipated operating events or performance which can reduce production or cause production to be shut in or delayed;
incorrect assessments of the value of acquisitions; the need to obtain required approvals from regulatory authorities; stock market volatility; volatility in market
prices for oil and natural gas; liabilities inherent in oil and natural gas operations; access to capital; and other factors. Readers are cautioned that this list of risk
factors should not be construed as exhaustive.
The forward-looking information contained in this presentation is expressly qualified by this cautionary statement. Underground does not undertake any obligation
to update or revise any forward-looking statements to conform such information to actual results or to changes in our expectations except as otherwise required by
applicable securities legislation. Readers are cautioned not to place undue reliance on forward-looking information.
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl has been used and is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
26

27. Notes to Disclosure
1. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations by application of future development projects. Prospective resources have both an associated
chance of discovery and a chance of development. There is no certainty that any portion of the prospective resources will be
discovered and, if discovered, there is no certainty that it will be commercially viable to produce any portion of those
resources. Prospective resources are undiscovered resources that indicate exploration opportunities and development
potential in the event a commercial discovery is made and should not be construed as reserves or contingent (discovered)
resources. Prospective resources in this presentation are reported on an unrisked, company interest basis.
2. The reserve and resource estimates in respect of the prospective resources for the Zaca Field for Underground were
prepared on October 27, 2011 with an effective date of November 1, 2011 and prepared in accordance with COGE
Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") by a member of
management of Underground who is a "qualified reserves evaluator" as defined under NI 51-101.
3. The "best estimate" is considered to be the best estimate of the quantity that will actually be recovered. In terms of
prospective resources, it is equally likely that the actual quantities recovered will be greater or less than the best estimate. In
terms of discovered reserves, the “best estimate” is the combination of the proved plus probable reserves. If probabilistic
methods are used, there should be at least a 50 percent probability that the quantity actually recovered will equal or exceed
the best estimate.
4. The significant positive factors that are relevant to the management's estimate of the reserves and prospective resources
include production in close proximity to the assets and oil and gas shows in wells drilled in close proximity to the assets. A
significant negative factor that is relevant to management's estimate of prospective resources is that seismic attribute
mapping in the areas can be indicative but not certain in identifying resources.
5. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a
10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible
reserves.
6. The estimates of reserves and resources for individual properties may not reflect the same confidence level as estimates of
reserves and resources for all properties, due to the effects of aggregation.
7. Historical production data for both Zaca and Lompoc is based upon a report titled "California Monterey Reservoir Study
Project", prepared by Spivak, Mannon, Brigham, Surdam, Coombs, and Sageev and dated September 11, 1985 and the
records of the California Division of Oil and Gas and Geothermal Resources obtained by the Company on August 24, 2011.
27

28. Appendix

29. Management Team
Mike Kobler, Chairman, CEO and President
 35 years international project management and engineering experience
 Founder of successful OSUM Oil Sands Corp., Calgary
 Founder and President, UCM Civil Engineering Consulting Firm focused on large infrastructure construction projects in California
Bruce Berwager, COO - Masters Petroleum Eng, P.Eng
 32 years international oil and gas exploration, development, operations management and engineering roles with Chevron, Unocal,
Conoco, Venoco and others
 20+ years experience with Shale in California (Monterey), Texas (Barnett & Wolfcamp), Pennsylvania (Marcellus)
 Former Director and COO of Venoco, SVP and GM for California Ops-Warren Resources
Peter Ballachey, CFO and Corporate Secretary - CA, MS
 35 years experience including 16 years senior financial CFO roles in Canada and USA
 Former CFO of OSUM Oil Sands Corp., Calgary
Simon Clarke, VP Corporate Development and Director, LLB
 Over 20 years capital markets experience
 Founder, Board Observer and Advisor to OSUM Oil Sands Corp
 Managing Director Invico Energy II Fund, Director of Argus Metals Corp., Director of Underground Energy, Inc.
David Hoyt, VP Exploration & Development – CPG, RPG
 Over 35 years exploration and development geology and geophysics project management and interpretation experience with ARCO,
TXO, Warren, Foothill and as an independent consultant
 Extensive academic and Industry experience in California, Nevada, Alaska
Randy Ray, Chief Geophysicist – BS, MS
 36 years experience in Western US and an expert in integrated seismic and geological interpretation
 Professional Geologist, Texas and Wyoming
29

30. Independent Directors
Randy Aldridge – Independent Director
 35 years international oil experience: Chairman- Koch Pipelines, President- Koch Petroleum Canada, President-Koch Oil Co.,
Chairman-True Energy Corp.
 Board Member, Energy Holdings international Inc. and Husky/BP Toledo Refinery LLC
Harland Johnson – Independent Director
 45 years technical and management experience in the upstream petroleum industry for Exxon Corporation and its affiliates
 Formerly Presidente, Divisão de Exploração e Produção, Esso Brasileira de Petróleo Limitada; and President, Exxon Trinidad Limited
 BSc (Honors) Chemistry, U of Alberta. PhD Metallurgy, U of Alberta
Andrew Squires – Independent Director
 23 years experience in heavy oil and oil sands at Petro-Canada, Dome, Amoco, Paramount
 Sr. Vice-President, OSUM Oil Sands Corp.
Douglas Urch – Independent Director
 Over 30 years oil & gas experience at RallyEnergy, Mohave Exploration, Sunshine Oilsands, Barrington Petroleum, TriGas Exploration
and Ryerson Oil & Gas
 EVP, Finance and CFO Bankers Petroleum Ltd.
 Director and Audit Committee Chairman at Petrodorado Energy
30

31. Key California Players
 Largest Monterey Shale land holder in the State  Ranked #1 in daily oil-equivalent production in
(LA, Ventura and San Joaquin Basins) California in 2011
 10-15 exploratory wells per year planned  2011 California operated production of 183,000
through 2015 to test shale prospects, $6.3 billion BOE/D, consisting of 165,000 bpd of crude oil
CAPEX forecast over next four years  Primarily operates in the San Joaquin Basin
Monterey Diatomite is the key producer / target
 1.2 million acres in Monterey and 520 drilling
targets de-risked for oil-prone shale  74 million barrels of oil produced by operations
development in the San Joaquin Valley in 2007, roughly 32%
of the state’s annual oil production
 Spent $1.6 billion on California in 2011 and is
operating 30 rigs– IPs of 300-400+  Predominately steamflood operations in heavy
oil reservoirs (Kern River, Midway-Sunset, Lost
 Now producing approx. 139,000 boepd from Hills, Cymric, Coalinga, San Ardo)
Monterey and equivalent Shales
Other Players in the Santa Maria Basin
31

32. History of Monterey Shale
1895: 1st Monterey production in state at
t
1
Midway Sunset field
1901: Union discovers Monterey Fractured
play at Orcutt Field, several more Monterey
t
2
fields developed in Santa Maria Basin from
1901 - 1942
t
4
t
5 1970’s-1990’s: Majors discover large Offshore
Monterey Fractured fields-Hondo, Pt. Arguello,
t
6 t
3
Pt. Pedernales, Sacate, Pescado, S. Ellwood
fields
t
1
t
2 1980’s:Shell/Chevron/Mobil develop
t
4 Monterey Diatomite with vertical frac’d wells
at Belridge and Lost Hills fields
1990’s: EOG develops diagenetic fractured
t
5
Monterey at Rose and N. Shafter fields
t
3 7
1998: Oxy begins development of Monterey
t
6
matrix at Elk Hills field
2005-11: Oxy explores and develops
7
7 Monterey equivalent formations in Ventura
and Los Angeles Basins
32

33. Monterey Play Types
UE’s Initial Monterey Prospects are Naturally Fractured, Conventional Structures
Cat Canyon-Gato Ridge South Belridge
147 MMBO Zaca Extension 540 MMBO
21 MMBO Cuyama Elk Hills North Shafter
230 MMBO 17 MMBO
Pt. Pedernales Hondo
Orcutt
Asphaltea 86 MMBO
90 MMBO 427 MMBO
209 MMBO Closures
103 MMBO
Monterey Formation
San Andreas Fault
OFFSHORE-ONSHORE MONTEREY OUTBOUND BASINS ONSHORE SAN JOAQUIN INBOUND BASIN
Fracture Dominated Matrix Dominated
135 Miles
 Fracture Dominated
• Outward basins – Structural traps – Hondo, Pt. Pedernales, Orcutt, Cat Canyon, Asphaltea – cleaner shales
• Inward basins – Diagenetic traps – Rose, North Shafter
 Matrix Dominated: Mostly Diatomite – Belridge, Lost Hills, Elk Hills, Cymric, McKittrick
 Dual Porosity: Matrix, micro-fractures and fractures – S. Ellwood, Midway-Sunset
33

34. US Shale Oil Comparison
Formation Gross Matrix Matrix Total Organic
Play
Depth (ft) Thickness (ft) Porosity (%) Permeability (md) Content (%)
Bakken 7,000-11,000 20-150 3-12 0.005-0.2 2-18
High Profile US
Oil-Prone Eagle Ford 8,0000-14,000 75-300 3-15 <0.0001-0.003 4.7
Shale Plays
Niobrara 2,000-8,000 >150 4-8 na 5
Monterey (SMV) 3,500-10,000 500-3,500 5-30 0.0001-2 4-5
California Monterey(SJV) 5,000-13,000 500-5,000 15-30 0.0001-2 0.1-4
Resource Shale
Plays Tumey 3,000-19,000 200-700 5-10 0.001 0.9-3.2
Kreyenhagen 3,000-19,000 400-2,400 5-10 <0.0001-1 4-12
Moreno (Gas) 4,000-14,000 100-11,000 na na 0.5-4
Nevada Chainman/Pilot > 8,200 400-2,400 5-10 Fracture Enhanced 1.5-11.7
Emerging Shale
Plays Paleozoic >8,200-15,000 2,000-3,000 Fracture Enhanced Fracture Enhanced 4.4-25
Key Attributes of Commercial Resource Plays
TOC in excess of 1%
T-MAX of 450⁰F
Enhanced Permeability from Interbedded Sand/Carbonates or Natural Fractures
34

35. Local Prices
based on NYMEX Futures Strip
NYMEX Futures Strip Price as of May 31, 2012
Crude Oil Prices Natural Gas Prices
Current Current Local Gas
WTI @ SMV Local Gas
Differential Differential NYMEX Price
Year Cushing Crude Oil Price
MWSS (1) SMV (2) Henry Hub Differential
Oklahoma Forecast
vs WTI vs MWSS
$US/bbl $US/bbl $US/bbl $US/bbl $US/mmbtu % of HH Nymex $US/mmbtu
2012 $94.14 $8.82 ($4.36) $98.60 $2.50 104% $2.60
2013 $84.90 $8.82 ($4.36) $89.36 $3.37 104% $3.50
2014 $84.60 $8.82 ($4.36) $89.06 $3.39 104% $3.53
2015 $84.66 $8.82 ($4.36) $89.12 $4.30 104% $4.47
2016 $84.86 $8.82 ($4.36) $89.32 $4.46 104% $4.64
2017 $85.19 $8.82 ($4.36) $89.65 $4.62 104% $4.80
2018 $85.64 $8.82 ($4.36) $90.10 $4.81 104% $5.00
2019 $86.02 $8.82 ($4.36) $90.48 $5.03 104% $5.23
2020 $86.44 $8.82 ($4.36) $90.90 $5.26 104% $5.47
2021+ $86.44 $8.82 ($4.36) $90.90 $5.26 104% $5.47
1. MWSS is an abbreviation for Midway Sunset, the benchmark for California heavy oil at 13˚ API
35
2. SMV is an abbreviation for Santa Maria Valley crude oil at 15˚ API