1. Underground Energy Corp.
Unlocking Shale Oil Opportunities in California & Nevada
TSX-V:UGE
Corporate Presentation
OGIS April 2012

2. California Focused Operations
 Currently 69,291 net acres under lease in
California and Nevada
 30,320 net acres prospective in prolific
CALIFORNIA Monterey shales in Santa Maria and San
Joaquin Basins
• Initial focus is conventional oil recovery from
NEVADA naturally fractured Monterey targets
San Francisco • 2 existing, producing wells - 80 bopd
• 5-10 well initial drilling program underway
• Potential new discovery - 900 feet contiguous,
quality oil shows from initial drilling at Zaca
Las Vegas
• Management’s initial estimates at Zaca of 6
MMbbls 2P reserves / 20.8 MMbbls
prospective resources1
Los Angeles
Zaca  7,685 net acres of non shale prospects in the
San Joaquin Basin
 31,286 net acres in 6 prospects in Nevada
Underground leases
1. Management estimates which also include a review by an internal qualified reservoir engineer 2

3. A Team Built for California Oil
Management Independent Board Members
Michael Kobler – Founder, Chairman, Bruce Berwager – Chief Operating Officer Randy Aldridge - Director
President & CEO 32 years international oil & gas experience; 35 years international oil experience;
35 years oil & large infrastructure projects Chevron, Unocal, Conoco, Warren President of Koch Pipelines & Koch
globally and in California; former COO and Director of Venoco; Petroleum Canada; Koch Oil Co., True Energy
Founder and former CEO 20+ years shale experience
of OSUM Oil Sands in CA, TX, PA
Peter Ballachey – Founder, CFO & Corporate Simon Clarke – VP Corporate Development Harland Johnson - Director
Secretary 20+ years capital markets experience; 45 years technical and management
35 years international financial experience; RailPower, Director of Invico Energy and upstream experience in Trinidad & Brazil:
Canadian Pacific, RailPower, BC Rail Argus Metals, ExxonMobil and affiliates
and CFO at OSUM Oil Sands Founder of OSUM Oil Sands
Dana Brock – VP Engineering David Hoyt – VP Exploration & Development Andrew Squires - Director
33 years California energy and infrastructure 40+ years in exploration and development 23 years heavy oil experience;
experience; ARCO, Unocal, Radian and geology and geophysics; 25 years in California Petro-Canada, Dome, Amoco, Paramount;
OSUM Oil Sands with ARCO, TXO, Warren, Foothill current Senior VP OSUM Oil Sands
Randy Ray – Chief Geophysicist Kim Wolfe – Regulatory Mgr. & Compliance Douglas Urch - Director
36 years in western US; expert in integrated 13 years oil & gas experience in CA and Santa 30+ years international experience;
seismic and geological interpretation ; Barbara permitting and regulatory; CFO Bankers Petroleum and previously CFO
BreitBurn, Encana, PanCanadian Venoco, Greka, SCS of Rally Energy
 California-based team with proven track record of creating significant shareholder value
• Founders of OSUM Oil Sands Corp. ($2.0 billion private oil sands company based in Calgary, AB)
California-based
• Operations team with proven track record of finding and growing reserves & production in California
Note: Refer to the Appendix for detailed description of the Company's management team and board of directors 3

4. Capital Structure Snapshot
UGE $0.245
Listed on the TSX Venture Exchange April 11, 2012 Closing Share Price
204.2 million $50.0 million
Basic Shares Issued and Outstanding Market Capitalization (on Basic Shares)
337.9 million $16.0 million
Fully Diluted Shares Outstanding Cash Balance at December 31, 2011
16.5% $31.0 million
Insider Ownership Working Capital at December 31, 2011
25.9% $39.7 million
Institutional Ownership Enterprise Value (on Basic Shares)
57.6% $37.0 million
Retail Ownership Potential Proceeds from Dilutive Securities
4

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

6. 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
Has 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 Shale is the largest
shale oil formation in the US
with an estimated 15.4 billion
Ventura & Santa Barbara Channel Los Angeles
barrels, 2/3rd of total oil shale
Underground Monterey prospects
potential
Los Angeles Basin
1. Source: California DOGGR and USGS 6

7. Key Monterey Players
 Largest Monterey land holder in State (LA,  Again ranked #1 in daily oil-equivalent
Ventura and San Joaquin basins) production in California in 2011
 2011 California production of 183,000 barrels,
 10-15 exploratory wells per year planned
consisting of 165,000 of crude oil
through 2015 to test shale prospects
 Primarily operates in the San Joaquin Basin
 200,000 acres and 520 drilling targets and Monterey shale is a key producer / target
de-risked for oil-prone shale development
 74 million barrels of oil produced by operations
 $1.5 billion capex budget for California (195 in the San Joaquin Valley in 2007, roughly 32%
shale wells in 2011 – IPs of 300+) of the state’s annual oil production
 Now Producing approx. 50,000 bopd from  Waterflood operation in Kern County, California
Monterey and equivalent shales has an average production of 72,000 bopd
Other players
7

8. Monterey Shale Type Curves
BOPD
1000 700,000
EUR~ 650 MB at 30 years 600,000
275 Oxy Monterey Type Curve (100+ wells)
200
500,000
100 EUR~ 543 MB at 30 years
400,000
Zaca Field Vertical Well Normalized Monterey Type Curve (61 wells) 300,000
10
200,000
100,000
1 -
0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 216 228 240 252
Months
1. Source: Occidental Petroleum Corporation, Minerals Management Service, DOGGR 8

9. Oil Pricing Comparison
California (CA) MWSS begins
$120.00 trading at a $120.00
 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)
 CA is not connected to other US oil supply or markets
$100.00 $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 $80.00
$70.00
$60.00 $60.00
$50.00
$40.00 $40.00
WTI Western Texas Intermediate- 39.6 API
MWSS Midway Sunset- 13.0 API
$30.00
WCS Western Canada Select- 20.6 API
$20.00 $20.00
Jan-09 Jan-10 Jan-11 Jan-12
9

10. Santa Barbara County, California
 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 Asphaltea
Canyon Prospects
251
Orcutt North
Pacific
Ocean
209 28
PXP/Lompoc
73
Oil & Gas Plant
Santa Barbara Gato Ridge
South
County 54
Barham Zaca
Los Alamos
Ranch
To Los Angeles 35
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 and BOEMRE 10

11. Zaca Extension Project
 Santa Barbara County, California
San Francisco 10 0 10 20 30 40 50 miles
Modesto
 80% WI (Operator)
Merced
County  7,750 gross acres (6,200 net acres)
Stanislaus
County San Joaquin Basin  Existing field has produced 32 MMbbls oil
Madera
County  Monterey is key target
Challenger
Fresno
County
 Several new structures identified by
San Benito Fresno seismic
County
Burrel  Permitting completed for 2 well pads & 6
drilling locations
Pacific Kings
County
Tulare
County  Initial 5 well drilling program commenced
Ocean late February
 Chamberlin 4-2 well identified potential
Petroleum Basin
Producing Oil Field Devil’s Den Buttonwillow
new discovery with 900 feet of strong oil
Producing Gas Field shows
Underground Property San Luis Obispo
County Bakersfield  Potential virgin pressure
Highlighted Property
 Next well will target and production test
Kern
Santa Maria Basin County newly discovered Chamberlin East Block
Asphaltea  6 MMbbls 2P Reserves1
Santa Rita
Zaca Santa Barbara
County  20.8 MMbbls Prospective Resources1
Santa Barbara
1. Management estimates which also include review by an internal qualified reservoir engineer 11

12. Underground’s
Zaca
Assets
• Historic recovery rates
6.8%
• Primary recovery
techniques only
• Potential to increase
96.2 acres
recovery rates further Permitted Site B Permitted Site D
• Latest seismic
220.8 acres
techniques
128.8 acres
• Deviated /
horizontal drilling 269 acres
365 acres
• Possible EOR
• Thermal testing 381.5 acres
1964-1967
• Waterflooding
380.7 acres
1953-1954
Existing Oil Well
Underground Energy Lease Boundary 1,842 Total Acres
Zaca Oil Field Recognized Boundary Seismically
Existing Zaca Field
Probable Geologic Structure Identified by Seismic Defined
Possible Geologic Structure Identified by Seismic
Existing Seismic Line circa 1986
New Seismic Line circa 2011
Permitted Pad Locations
Initial Well Locations
Potential Well Site 12

13. Zaca Well Economics
Zaca Field – All Historic Wells
Typical Well All Wells Infill Wells Normalized Type Curve (61 wells)
250
Type Curve Type Curve
200
Well Depth (MD feet) 5,500-7,500 4,500-6,500
Dry Hole Well Costs ($M) $1,300-$2,000 $1,200-$1,800 150
Completion Cost ($M) $200-$400 $200-$400 100
Total Well Cost ($M) $1,500-$2,400 $1,400-$2,200 50
UGE Interest (WI / NRI) 80% / 62.6% 80% / 62.6% 0
0 60 120 180 240 300 360
Initial Prod Rate (BOPD) 205 70
Zaca Field – Infill Wells Drilled 1971 to Present
Cum. Production (MBO) 535 375 Normalized Type Curve (18 wells)
250
NPV @10% BT ($M)1 $ 11,325 $ 7,663
200
IRR (%) 200% 85% 150
Payback (years) 0.5 1.2 100
50
0
0 60 120 180 240 300 360
1. Economics are internal estimates using NYMEX Futures Strip Prices as of March 31, 2012 with $14.74 deduction for diluent, gravity, location
13

14. Zaca Initial Build-Out Profile
6000 Key Assumptions $800
5677
 60 well build out – within official field boundary $725
 IP per well = 135 bopd
$700
 1 well per month from mid 2012
5000  2 wells per month from Jan 2014
 Primary recovery only no EOR $600
Cumulative Net Cash Flow ($USMM)
4000 $500
Daily Gross Production (bopd)
$400
3000
$300
2000 $200
$100
1000
590
$0
0 -$100
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Calendar Year
1. Economics are based on management estimates of production post-royalty and based on March 31, 2012 NYMEX Futures strip prices 14

15. Zaca Extended Build-Out Profile
12000 Key Assumptions $1,600
 120 well build out – based on current structures only
 IP per well = 135 bopd $1,392
$1,400
 1 well per month from Jan 2012
10000  2 wells per month from Jan 2014 9593
 Primary recovery only no EOR $1,200
Cumulative Net Cash Flow ($USMM)
8000 $1,000
Daily Gross Production (bopd)
$800
6000
$600
4000 $400
$200
2000
$0
590
0 -$200
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Calendar Year
1. Economics are based on management estimates of production post-royalty and based on March 31, 2012 NYMEX Futures strip prices 15

16. Other California Assets – Santa Maria
Asphaltea
San Francisco 10 0 10 20 30 40 50 miles
 Santa Barbara County, California
Modesto
Merced  100% WI (Operator), 5,850 net acres
County
Stanislaus  Monterey shale oil targets
County San Joaquin Basin
 Analog fields: Zaca (32 MMboe), Cat Canyon (251
Madera
County Mmboe), Orcutt (209 Mmboe)
Fresno
County
 Work at Zaca also relevant for 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  High impact exploration project
Producing Oil Field
Producing Gas Field
Underground Property San Luis Obispo Santa Rita
Bakersfield
Highlighted Property
County
 Santa Barbara County, California
 80% WI (Operator), 1,217 gross acres (974 net
Kern
Santa Maria Basin County acres)
 Monterey shale & Point Sal sand oil targets
Asphaltea
Santa Rita Zaca Santa Barbara  On trend with Lompoc Field (52 MMbbls)
County
Santa Barbara
1. Source: GLJ Petroleum Consultants, effective date June 1, 2011 16

17. Other California Assets – San Joaquin
Devil’s Den
San Francisco 10 0 10 20 30 40 50 miles  Kern County, California
Modesto
Merced
 65% WI (Operator), 5,336 gross acres (4,955 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
 80% WI, 10,609 gross acres (8,487 net acres)
San Benito Fresno
County  Zilch & Vaqueros sand, Monterey & Kreyenhagen oil targets
 1 producing well (65 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  80% WI (Operator), 1,445 gross acres (1,156 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
 70.49% WI (Operator),10,902 gross acres (7,685 net acres)
Santa Rita Zaca Santa Barbara
 32 miles existing 3D seismic
County  Ziltch, Blewett, Vaqueros/Temblor sands; and Kreyenhagen
Santa Barbara & Moreno shale gas targets
1. Source: GLJ Petroleum Consultants, effective date December 31, 2011 17

18. Nevada Assets
 “Early mover” advantage by building a strong
Bull Run
land position ahead of the curve
Deadman
Winnemucca Elko Creek  Land lease prices have increased significantly
in the last year
 Complex geology, but existing discoveries have
Blackburn had very high production rates
West
 Emerging shale oil potential (Bakken-like)
Reno
RAILROAD VALLEY
 Key competitors will help prove up plays -
46.2MMBO Cabot (COG), EOG (EOG), SM Energy (SM),
Trap Callon (CPE), PetroHunt
Springs Flat Top
Coaldale
 Deadman Creek– 2D seismic
purchased, interpretation begun
 Blackburn – 2D and 3D seismic
purchased, interpretation begun
 Coaldale – Offset exploratory well
Las
Vegas drilling
 Bull Run – Surface geological
mapping underway
Underground leases
18

19. GLJ Reserves Report December 31, 2011
Reserves Category Gross (1) Net (2) Before Tax NPV 10
Mbbls (3) Mbbls (3) (thousands of US $) (5) (6) (7)
Total Proved (1P) 566 445 $9,007
Total Probable 1,479 1,161 $31,658
Total Proved + Probable (2P) 2,045 1,606 $40,665
Total Possible (4) 2,119 1,662 $40,938
Total Proved + Probable + Possible (3P) 4,161 3,268 $81,603
Notes:
1. "Gross" reserves means Underground's working interest (operating and non-operating) share before deduction of royalties and without including any
royalty interest of Underground.
2. "Net" reserves means Underground's working interest (operating and non-operating) share after deduction of royalty obligations, plus Underground's
royalty interest in reserves.
3. Totals for each category are reported on an "oil equivalent" basis which represents total light oil and heavy oil, in thousands of barrels of oil.
4. 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.
5. The estimated future net revenues are stated before deducting future estimated site restoration costs and are reduced for estimated future
abandonment costs and estimated capital for future development associated with the reserves.
6. All future net revenue values calculated utilizing GLJ January 1, 2012 oil price forecast for WTI delivered into Cushing, OK corrected for oil gravity and
local price differentials.
7. It should not be assumed that the discounted future net revenues estimated by GLJ represent the fair market value of the reserves.
8. This is a summary table, please refer to the press release dated April 10, 2012 for additional detail
19

20. Initial Exploration and Development Plan
Activity 1Q12 2Q12 3Q12 4Q12 Net Cost ($MM)
Acquire & Process Seismic $0.2
(30 mi 2D)
Drill 5 Monterey Shale Wells $10.3
Zaca
Design & Build Facilities $1.8
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 sqmi $0.1
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
20

21. Initial Development Profile
700 Key Assumptions $9,000,000
 5 producing wells in 2012 639 $8,209,978
 IP per well = 135 bopd $8,000,000
590
600  Primary recovery only
$7,000,000
Cumulative Operating Cash Flow ($USMM)
500
Daily Gross Production (bopd)
$6,000,000
400 $5,000,000
300 $4,000,000
$3,000,000
200
135 $2,000,000
100
$1,000,000
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 March 31, 2012 NYMEX Futures strip prices 21

22. Company Timeline
Commenced
initial drilling
program in
Built land California
position to
Permit for ~80,000 net Continue to
Focus on initial 26 acres in de-risk and
permitting wells granted California and permit core
process Nevada assets
Rounded out
Initial Added senior IPO and Target exit
Company Monterey California management raised $25.5 Production
Inception Lease expertise team million 600+ bbls
2007 2008 2009 2010 2011 2012
22

23. 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
bberwager@ugenergy.com
Phone: (805) 845-4700, x11
VP Corp Development – Simon Clarke
simon.clarke@ugenergy.com
Phone: (604) 551-9665
23

24. 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.
24

25. 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.
25

26. Appendix

27. 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
Kim Wolfe, Regulatory Manager and Compliance Officer – Paralegal, NP
 13 years oil and gas experience with Venoco, Greka, Tracer in land, legal and compliance roles
 California and Santa Barbara permitting and regulatory expert
27

28. 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
Sam Charanek – Advisor to the Board
 15 years of capital markets and finance experience with a focus on international oil and gas strategies
 Co-founder of Pan Orient Energy, Canacol Energy, Excelsior Energy (now Athabasca), PetroDorado Energy and Mena Hydrocarbons
 Advised Zodiac Exploration, Gallic Energy and ArPetrol Energy and Sunshine Oilsands
28

29. History of Monterey Shale
1895: 1st Monterey production in state at
t
1
Midway Sunset field
1901: Union discovers Monterey Fractured
t
2
play at Orcutt Field, several more Monterey
fields developed in Santa Maria Basin from
t
4 1901 - 1942
t
5 1970’s-1990’s: Majors discover large Offshore
t
6 t
3 Monterey Fractured fields-Hondo, Pt. Arguello,
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
t
1990’s: EOG develops diagenetic fractured
5
t
3 7
Monterey at Rose and N. Shafter fields
t
1998: Oxy begins development of Monterey
6
matrix at Elk Hills field
2005-11: Oxy explores and develops
7
7 Monterey equivalent formations in Ventura
and Los Angeles Basins
29

30. 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
30

31. 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
31

32. US Oil Play Comparison
Technically
Well Cost EUR/well IP Rate Well Cost/EUR
Play Recoverable
($US MM) (MBOE) (BOEPD) ($/BOE)
(BBO)1
Louisiana Tuscaloosa N/A $12.0-14.0 400-600 700-900 $23-30
Colorado Niobrara N/A $4.7-5.2 200-300 250-300 $17-24
Ohio Utica N/A $3.0-5.0 200-300 200-250 $15-17
Texas Wolfberry N/A $1.8-2.0 120-170 100-125 $12-15
Texas Avalon/Bone Springs 1.6 $5.5-6.0 330-550 500-550 $11-16
N. Dakota/Montana Bakken 3.6 $7.0-9.0 500-600 500-900 $10-14
Texas Eagle Ford Oil 3.4 $4.0-6.5 250-350 500-600 $8-11
Oklahoma Mississippian Lime N/A $3.0-3.5 300-400 275-325 $8.50-10
California Monterey (SMV) 15.4 $2.0-2.5 375-550 200-300 $4.50-5.50
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. 32

33. Local Prices
based on NYMEX Futures Strip
NYMEX Futures Strip Price as of March 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 $105.55 $10.45 ($5.06) $110.94 $3.18 81% $2.58
2013 $102.87 $10.45 ($5.06) $108.26 $3.88 81% $3.14
2014 $98.77 $10.45 ($5.06) $104.16 $4.24 81% $3.43
2015 $96.02 $10.45 ($5.06) $101.41 $4.51 81% $3.65
2016 $94.33 $10.45 ($5.06) $99.72 $4.75 81% $3.85
2017 $93.89 $10.45 ($5.06) $99.28 $5.00 81% $4.05
2018 $93.00 $10.45 ($5.06) $98.39 $5.25 81% $4.25
2019 $92.81 $10.45 ($5.06) $98.20 $5.50 81% $4.46
2020 $92.37 $10.45 ($5.06) $97.76 $5.76 81% $4.67
2021+ $90.00 $10.45 ($5.06) $95.39 $6.03 81% $4.88
1. MWSS is an abbreviation for Midway Sunset, the benchmark for California heavy oil at 13˚ API
33
2. SMV is an abbreviation for Santa Maria Valley crude oil at 15˚ API