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Corporate PresentationOGIS April 2012
Underground Energy Corp.Unlocking Shale Oil Opportunities in California & NevadaTSX-V:UGE
California Focused Operations
San Francisco
Los Angeles
Las Vegas
CALIFORNIA
NEVADA
Underground leases
21. Management estimates which also include a review by an internal qualified reservoir engineer
Zaca
Currently 69,291 net acres under lease in California and Nevada
30,320 net acres prospective in prolific Monterey shales in Santa Maria and San Joaquin Basins
• Initial focus is conventional oil recovery from naturally fractured Monterey targets
• 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• Management’s initial estimates at Zaca of 6
MMbbls 2P reserves / 20.8 MMbblsprospective resources1
7,685 net acres of non shale prospects in the San Joaquin Basin
31,286 net acres in 6 prospects in Nevada
Note: Refer to the Appendix for detailed description of the Company's management team and board of directors 3
California-based
Management Independent Board MembersMichael Kobler – Founder, Chairman,
President & CEO35 years oil & large infrastructure projects
globally and in California; Founder and former CEO
of OSUM Oil Sands
Bruce Berwager – Chief Operating Officer32 years international oil & gas experience;
Chevron, Unocal, Conoco, Warrenformer COO and Director of Venoco;
20+ years shale experience in CA, TX, PA
Randy Aldridge - Director35 years international oil experience;
President of Koch Pipelines & Koch Petroleum Canada; Koch Oil Co., True Energy
Peter Ballachey – Founder, CFO & Corporate Secretary
35 years international financial experience; Canadian Pacific, RailPower, BC Rail
and CFO at OSUM Oil Sands
Simon Clarke – VP Corporate Development20+ years capital markets experience;
RailPower, Director of Invico Energy and Argus Metals,
Founder of OSUM Oil Sands
Harland Johnson - Director45 years technical and management
upstream experience in Trinidad & Brazil: ExxonMobil and affiliates
Dana Brock – VP Engineering33 years California energy and infrastructure
experience; ARCO, Unocal, Radian and OSUM Oil Sands
David Hoyt – VP Exploration & Development40+ years in exploration and development
geology and geophysics; 25 years in California with ARCO, TXO, Warren, Foothill
Andrew Squires - Director23 years heavy oil experience;
Petro-Canada, Dome, Amoco, Paramount; current Senior VP OSUM Oil Sands
Randy Ray – Chief Geophysicist36 years in western US; expert in integrated
seismic and geological interpretation ;BreitBurn, Encana, PanCanadian
Kim Wolfe – Regulatory Mgr. & Compliance 13 years oil & gas experience in CA and Santa
Barbara permitting and regulatory;Venoco, Greka, SCS
Douglas Urch - Director30+ years international experience;
CFO Bankers Petroleum and previously CFO 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)• Operations team with proven track record of finding and growing reserves & production in California
A Team Built for California Oil
Capital Structure Snapshot
4
UGEListed on the TSX Venture Exchange
204.2 millionBasic Shares Issued and Outstanding
337.9 millionFully Diluted Shares Outstanding
16.5%Insider Ownership
25.9%Institutional Ownership
57.6%Retail Ownership
$0.245April 11, 2012 Closing Share Price
$50.0 millionMarket Capitalization (on Basic Shares)
$16.0 millionCash Balance at December 31, 2011
$31.0 millionWorking Capital at December 31, 2011
$39.7 millionEnterprise Value (on Basic Shares)
$37.0 millionPotential Proceeds from Dilutive Securities
5Source of slide stats: California DOGGR (2001), US Department of Interior Bureau of Land Management
• 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
• 5 of the 10 largest discovered fields in US
• 54,000 producing wells in 2011
• California refinery oil sources in 2011:
California’s Petroleum Basins
Oil and Gas Fields in California
37%
13%
15%
11%
8% 16%California
Alaska
Saudi Arabia
Ecuador
Iraq
Other
San Joaquin Basin
Ventura & Santa BarbaraChannel
Los Angeles Basin
Santa Maria Basin
Los Angeles
Santa Barbara
San Francisco
Bakersfield
Sacramento Basin Total oil refining capacity in State is 2 million bopd
Pacific Ocean
Zaca
6
Monterey Shale Formation
World Class Source RockOver 290 billion barrels of oil generated1
World Class Reservoir RockHas produced over 2.5 billion barrels1
High organic content of 4-5%
Extremely thick shale packages of 500-3,500 ftCompared to other US shale plays:
Bakken: 20-150 ft, Eagle Ford: 75-300 ft, Niobrara: >150 ft
San Joaquin Basin
Ventura & Santa Barbara Channel
Los Angeles Basin
Santa Maria Basin
Los Angeles
Monterey Shale is the largest shale oil formation in the US with an estimated 15.4 billion barrels, 2/3rd of total oil shale
potentialUnderground Monterey prospects
1. Source: California DOGGR and USGS
Significant Monterey Shale Basins
7
Other players
Key Monterey Players
Largest Monterey land holder in State (LA, Ventura and San Joaquin basins)
10-15 exploratory wells per year planned through 2015 to test shale prospects
200,000 acres and 520 drilling targets de-risked for oil-prone shale development
$1.5 billion capex budget for California (195 shale wells in 2011 – IPs of 300+)
Now Producing approx. 50,000 bopd from Monterey and equivalent shales
Again ranked #1 in daily oil-equivalent production in California in 2011
2011 California production of 183,000 barrels, consisting of 165,000 of crude oil
Primarily operates in the San Joaquin Basin and Monterey shale is a key producer / target
74 million barrels of oil produced by operations in the San Joaquin Valley in 2007, roughly 32% of the state’s annual oil production
Waterflood operation in Kern County, California has an average production of 72,000 bopd
275200
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
1
10
100
1000
0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 216 228 240 252
Months
Zaca Field Vertical Well Normalized Monterey Type Curve (61 wells)
Oxy Monterey Type Curve (100+ wells)
BOPD
EUR~ 650 MB at 30 years
EUR~ 543 MB at 30 years
Monterey Shale Type Curves
81. Source: Occidental Petroleum Corporation, Minerals Management Service, DOGGR
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$90.00
$100.00
$110.00
$120.00
Jan-09 Jan-10 Jan-11 Jan-12
WTI Western Texas Intermediate- 39.6 API
MWSS Midway Sunset- 13.0 API
WCS Western Canada Select- 20.6 API
Oil Pricing ComparisonCalifornia (CA)
CA imports 62% of crude oil (~ 1 MM bopd) by sea(Alaska, Saudi Arabia, Ecuador, Iraq, Columbia, Brazil, Angola, Russia, Oman, Venezuela, Argentina, Peru, & Australia)
CA is not connected to other US oil supply or markets
CA oil prices currently more reflective of world prices(e.g. Brent) than WTI
Rig availability with low servicing costs and year–round access to CA projects
MWSS begins trading at a
premium to WTI
9
Santa Barbara County, California
10
Santa BarbaraCounty
Pacific Ocean
Conoco PhillipsSanta Maria Refinery
Greka/Santa MariaAsphalt Refinery
PXP/LompocOil & Gas Plant
All American Pipeline
Monterey Oil Field
Pipeline
Oil and Gas separation,Treatment and GasProcessing Plant
Refinery
Foxen Canyon Trend
To San Francisco
To Los Angeles
Santa Barbara County
2010 oil production of 25 million bbls 69,000 bopd in 2010 (onshore 9,400/ offshore 59,600) 935 producing wells Approximately 2 billion bbls oil produced to date1
Cat Canyon251
Santa Maria207
Gato Ridge54
Orcutt209
Lompoc 52
Barham Ranch
All American Pipeline
Los Alamos
3 milesEstimated Ultimate Oil Recoveries (MMBO)
7328
North
South
Underground Leases
Asphaltea Prospects
Zaca35
To Los Angeles
1. Source: California DOGGR and BOEMRE
Zaca Extension Project
111. Management estimates which also include review by an internal qualified reservoir engineer
Santa Barbara County, California 80% WI (Operator) 7,750 gross acres (6,200 net acres) Existing field has produced 32 MMbbls oil Monterey is key target Several new structures identified by
seismic Permitting completed for 2 well pads & 6
drilling locations Initial 5 well drilling program commenced
late February Chamberlin 4-2 well identified potential
new discovery with 900 feet of strong oil shows Potential virgin pressure Next well will target and production test
newly discovered Chamberlin East Block 6 MMbbls 2P Reserves1
20.8 MMbbls Prospective Resources1
San FranciscoModesto
Fresno
Santa Barbara
San Joaquin Basin
Santa Maria Basin
StanislausCounty
Merced County
MaderaCounty
FresnoCounty
TulareCounty
KingsCounty
San Luis Obispo County
San Benito County
Producing Oil FieldProducing Gas Field
010 10 20 30 40 50 miles
KernCounty
AsphalteaSanta Rita Zaca
ButtonwillowDevil’s Den
Burrel
Challenger
Santa Barbara County
Petroleum Basin
BakersfieldUnderground PropertyHighlighted Property
PacificOcean
12
Underground’sZaca
Assets• Historic recovery rates
6.8% • Primary recovery
techniques only• Potential to increase
recovery rates further • Latest seismic
techniques• Deviated /
horizontal drilling • Possible EOR
• Thermal testing 1964-1967
• Waterflooding1953-1954
Permitted Site B Permitted Site D
Existing Oil WellUnderground Energy Lease BoundaryZaca Oil Field Recognized BoundaryExisting Zaca FieldProbable Geologic Structure Identified by Seismic
Existing Seismic Line circa 1986New Seismic Line circa 2011Permitted Pad Locations
Possible Geologic Structure Identified by Seismic
Initial Well LocationsPotential Well Site
380.7 acres
381.5 acres
269 acres365 acres
128.8 acres
220.8 acres
96.2 acres
1,842 Total Acres Seismically
Defined
Zaca Well Economics
13
Typical Well All Wells Type Curve
Infill WellsType Curve
Well Depth (MD feet) 5,500-7,500 4,500-6,500
Dry Hole Well Costs ($M) $1,300-$2,000 $1,200-$1,800
Completion Cost ($M) $200-$400 $200-$400
Total Well Cost ($M) $1,500-$2,400 $1,400-$2,200
UGE Interest (WI / NRI) 80% / 62.6% 80% / 62.6%
Initial Prod Rate (BOPD) 205 70
Cum. Production (MBO) 535 375
NPV @10% BT ($M)1 $ 11,325 $ 7,663
IRR (%) 200% 85%
Payback (years) 0.5 1.2
0
50
100
150
200
250
0 60 120 180 240 300 360
0
50
100
150
200
250
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
Zaca Field – All Historic Wells Normalized Type Curve (61 wells)
Zaca Field – Infill Wells Drilled 1971 to Present Normalized Type Curve (18 wells)
14
Zaca Initial Build-Out Profile
1. Economics are based on management estimates of production post-royalty and based on March 31, 2012 NYMEX Futures strip prices
Key Assumptions 60 well build out – within official field boundary IP per well = 135 bopd 1 well per month from mid 2012 2 wells per month from Jan 2014 Primary recovery only no EOR
590
5677$725
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
0
1000
2000
3000
4000
5000
6000
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Cum
ulat
ive
Net
Cas
h Fl
ow ($
USM
M)
Daily
Gro
ss P
rodu
ctio
n (b
opd)
Calendar Year
590
9593
$1,392
-$200
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
0
2000
4000
6000
8000
10000
12000
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Cum
ulat
ive
Net
Cas
h Fl
ow ($
USM
M)
Daily
Gro
ss P
rodu
ctio
n (b
opd)
Calendar Year
15
Zaca Extended Build-Out Profile
1. Economics are based on management estimates of production post-royalty and based on March 31, 2012 NYMEX Futures strip prices
Key Assumptions 120 well build out – based on current structures only IP per well = 135 bopd 1 well per month from Jan 2012 2 wells per month from Jan 2014 Primary recovery only no EOR
Other California Assets – Santa Maria
16
San FranciscoModesto
Fresno
Santa Barbara
San Joaquin Basin
Santa Maria Basin
StanislausCounty
Merced County
MaderaCounty
FresnoCounty
TulareCounty
KingsCounty
San Luis Obispo County
San Benito County
Producing Oil FieldProducing Gas FieldUnderground Property
010 10 20 30 40 50 miles
KernCounty
AsphalteaZaca Santa Barbara
County
Petroleum Basin
Bakersfield
Asphaltea Santa Barbara County, California 100% WI (Operator), 5,850 net acres Monterey shale oil targets Analog fields: Zaca (32 MMboe), Cat Canyon (251
Mmboe), Orcutt (209 Mmboe) Work at Zaca also relevant for Asphaltea 2 potential structures identified – naturally
fractured 26 permitted wells 30+ miles of 2D swath seismic acquired 2011
currently being processed 2 billion bbls OOIP / 109 MMbbls Prospective
Resources1
High impact exploration project
Santa Rita Santa Barbara County, California 80% WI (Operator), 1,217 gross acres (974 net
acres) Monterey shale & Point Sal sand oil targets On trend with Lompoc Field (52 MMbbls)
Highlighted Property
Santa Rita
PacificOcean
1. Source: GLJ Petroleum Consultants, effective date June 1, 2011
Other California Assets – San Joaquin
17
San FranciscoModesto
Fresno
Santa Barbara
San Joaquin Basin
Santa Maria Basin
StanislausCounty
Merced County
MaderaCounty
FresnoCounty
TulareCounty
KingsCounty
San Luis Obispo County
San Benito County
Producing Oil FieldProducing Gas FieldUnderground Property
010 10 20 30 40 50 miles
KernCounty
AsphalteaZaca
Burrel
Santa Barbara County
Petroleum Basin
BakersfieldHighlighted Property
Devil’s Den Buttonwillow
Challenger
PacificOcean
Santa Rita
Devil’s Den Kern County, California 65% WI (Operator), 5,336 gross acres (4,955 net acres) Shallow Monterey (Diatomite) and Tumey shale oil targets Existing 3D sesimic Analog fields: McKittrick (350 MMboe), Cymric (543 MMboe)Burrel Fresno County, California 80% WI, 10,609 gross acres (8,487 net acres) Zilch & Vaqueros sand, Monterey & Kreyenhagen oil targets 1 producing well (65 bopd) Existing 2D seismic 265,000 bbls 2P Reserves / 561,000 bbls 3P Reserves1
Analog fields: Helm (46 MMboe), Raisin City (47 Mmboe)\Buttonwillow Kern County, California 80% WI (Operator), 1,445 gross acres (1,156 net acres) Monterey/McClure shale, 44X and Randolph sand oil targets In middle of Oxy/Venoco 3D seismic survey Offset well planned by Venoco Analog fields: North Shafter (10 MMboe), Rose (4.8 MMboe)Challenger Madera and Merced Counties, California 70.49% WI (Operator),10,902 gross acres (7,685 net acres) 32 miles existing 3D seismic Ziltch, Blewett, Vaqueros/Temblor sands; and Kreyenhagen
& Moreno shale gas targets
1. Source: GLJ Petroleum Consultants, effective date December 31, 2011
Nevada Assets
“Early mover” advantage by building a strong land position ahead of the curve
Land lease prices have increased significantly in the last year
Complex geology, but existing discoveries have had very high production rates
Emerging shale oil potential (Bakken-like) Key competitors will help prove up plays -
Cabot (COG), EOG (EOG), SM Energy (SM), Callon (CPE), PetroHunt
Deadman Creek– 2D seismic purchased, interpretation begun
Blackburn – 2D and 3D seismic purchased, interpretation begun
Coaldale – Offset exploratory well drilling
Bull Run – Surface geological mapping underway
18
Underground leases
Blackburn West
Flat TopTrap Springs
Coaldale
Bull Run Deadman Creek
RAILROAD VALLEY46.2MMBO
Reno
Las Vegas
Winnemucca Elko
GLJ Reserves Report December 31, 2011
Reserves Category Gross (1)
Mbbls (3)Net (2)
Mbbls (3)Before Tax NPV 10 (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 $81,603
Notes:
1. "Gross" reserves means Underground's working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Underground.
2. "Net" reserves means Underground's working interest (operating and non-operating) share after deduction of royalty obligations, plus Underground's royalty interest in reserves.
3. Totals for each category are reported on an "oil equivalent" basis which represents total light oil and heavy oil, in thousands of barrels of oil.4. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the
quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.5. The estimated future net revenues are stated before deducting future estimated site restoration costs and are reduced for estimated future
abandonment costs and estimated capital for future development associated with the reserves.6. All future net revenue values calculated utilizing GLJ January 1, 2012 oil price forecast for WTI delivered into Cushing, OK corrected for oil gravity and
local price differentials.7. It should not be assumed that the discounted future net revenues estimated by GLJ represent the fair market value of the reserves.8. This is a summary table, please refer to the press release dated April 10, 2012 for additional detail
19
Initial Exploration and Development Plan
20
Activity 1Q12 2Q12 3Q12 4Q12 Net Cost ($MM)
Acquire & Process Seismic(30 mi 2D)
$0.2
Drill 5 Monterey Shale Wells $10.3
Design & Build Facilities $1.8
Permit Additional Drill Sites & Increase Acreage
$0.2
Acquire & Process Seismic at Devil’s Den (50 mi 2D) & Prepare to Drill
$0.2
Acquire Seismic at Buttonwillow (16 sqmi3D, 30 mi 2D) & Prepare to Drill
$0.1
Continue Leasing at MVA. Reprocess 3D Seismic & Prepare to Drill
$0.2
Zaca
DrillingSeismic Other
$13.0
OtherCA
activity
21
Initial Development Profile
1. Economics are based on management estimates of production post-royalty and based on March 31, 2012 NYMEX Futures strip prices
135
639
590
$8,209,978
$0
$1,000,000
$2,000,000
$3,000,000
$4,000,000
$5,000,000
$6,000,000
$7,000,000
$8,000,000
$9,000,000
0
100
200
300
400
500
600
700
May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12
Cum
ulat
ive
Ope
ratin
g Ca
sh F
low
($U
SMM
)
Daily
Gro
ss P
rodu
ctio
n (b
opd)
Month
Bopd Cumulative Operating Cash Flow
Key Assumptions 5 producing wells in 2012 IP per well = 135 bopd Primary recovery only
22
Company Timeline
Company Inception
2007
Initial Monterey
Lease
2008
Focus on permitting process
Added California expertise
2009
Permit for initial 26
wells granted
Rounded out senior
management team
2010
Built land position to
~80,000 net acres in
California and Nevada
IPO and raised $25.5
million
2011
Commenced initial drilling program in California
Continue to de-risk and permit core
assets
Target exit Production 600+ bbls
2012
Contact Information
Underground Energy Corp.3rd Floor7 W. Figueroa StreetSanta Barbara, CA, 93101-5109Tel: 805.845.4700Fax: 805.845.1177www.ugenergy.com
President & CEO – Mike [email protected]: (805) 845-4700, x18
CFO – Peter [email protected]: (805) 845-4700, x17
COO – Bruce [email protected]: (805) 845-4700, x11
VP Corp Development – Simon [email protected]: (604) 551-9665
23
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 isan exploration and production company focused on unlocking oil from shale plays, principally in the Western US. Underground Energy is traded on the TSXVenture 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 thispresentation includes, without limitation, statements with respect to: (i) the closing and closing date of the Company's proposed acquisition of oil and gas leases inCalifornia; (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 oiland 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 suchexpectations or assumptions will prove to be correct. In particular, assumptions have been made that: (i) Underground will be able to obtain equipment andregulatory approvals in a timely manner to carry out exploration and development activities; (ii) Underground will have sufficient financial resources with which toconduct its planned capital expenditures; and (iii) the current tax and regulatory regime will remain substantially unchanged. Certain or all of the forgoingassumptions 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 anduncertainties and other factors (many of which are beyond the control of Underground) that could cause actual events or results to differ materially from thoseanticipated 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/orinability to retain drilling rigs and other services; competition for, among other things, capital, acquisitions of reserves, undeveloped lands, skilled personnel andsupplies; risks associated to the uncertainty of reserve and resource estimates; governmental regulation of the oil and gas industry, including environmentalregulation; geological, technical, drilling and processing problems and other difficulties in producing reserves; the uncertainty of estimates and projections ofproduction, 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 marketprices 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 riskfactors 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 obligationto update or revise any forward-looking statements to conform such information to actual results or to changes in our expectations except as otherwise required byapplicable 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 conversionmethod primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
24
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 exceedthe 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
Appendix
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
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
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History of Monterey Shale
1895: 1st Monterey production in state at Midway Sunset fieldt1
1901: Union discovers Monterey Fractured play at Orcutt Field, several more Monterey fields developed in Santa Maria Basin from 1901 - 1942
t2
1970’s-1990’s: Majors discover large Offshore Monterey Fractured fields-Hondo, Pt. Arguello, Pt. Pedernales, Sacate, Pescado, S. Ellwood fields
t3
1980’s:Shell/Chevron/Mobil develop Monterey Diatomite with vertical frac’d wells at Belridge and Lost Hills fields
t4
1990’s: EOG develops diagenetic fractured Monterey at Rose and N. Shafter fieldst5
1998: Oxy begins development of Monterey matrix at Elk Hills fieldt6
2005-11: Oxy explores and develops Monterey equivalent formations in Ventura and Los Angeles Basins
7
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t1t2
t3
t4t5
t6
7
7
Monterey Play Types
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
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Matrix DominatedFracture Dominated135 Miles
OFFSHORE-ONSHORE MONTEREY OUTBOUND BASINS ONSHORE SAN JOAQUIN INBOUND BASIN
Cat Canyon-Gato Ridge147 MMBO
Pt. Pedernales90 MMBO
Asphaltea Closures
103 MMBO
Orcutt209 MMBO
Cuyama230 MMBO
Elk Hills86 MMBO
North Shafter17 MMBO
South Belridge540 MMBO
Hondo427 MMBO
Monterey Formation
UE’s Initial Monterey Prospects are Naturally Fractured, Conventional Structures
San Andreas Fault
Zaca Extension21 MMBO
Key Attributes of Commercial Resource Plays TOC in excess of 1% T-MAX of 450⁰F Enhanced Permeability from Interbedded Sand/Carbonates or Natural Fractures
Play Formation Depth (ft)
Gross Thickness (ft)
Matrix Porosity (%)
Matrix Permeability (md)
Total Organic Content (%)
Bakken 7,000-11,000 20-150 3-12 0.005-0.2 2-18
Eagle Ford 8,0000-14,000 75-300 3-15 <0.0001-0.003 4.7
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
Monterey(SJV) 5,000-13,000 500-5,000 15-30 0.0001-2 0.1-4
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
Chainman/Pilot > 8,200 400-2,400 5-10 Fracture Enhanced 1.5-11.7
Paleozoic >8,200-15,000 2,000-3,000 Fracture Enhanced Fracture Enhanced 4.4-25
US Shale Oil Comparison
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High Profile US Oil-Prone
Shale Plays
California Resource Shale
Plays
Nevada Emerging Shale
Plays
PlayTechnically
Recoverable (BBO)1
Well Cost($US MM)
EUR/well(MBOE)
IP Rate(BOEPD)
Well Cost/EUR($/BOE)
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
US Oil Play Comparison
321. Sources: US EIA Review of Emerging Resources: US Shale Gas and Shale Oil Plays dated July 2011, Devon’s Analyst Day Presentationdated April 4, 2012, and actual costs of Underground Energy, Inc.
Local Pricesbased on NYMEX Futures Strip
331. MWSS is an abbreviation for Midway Sunset, the benchmark for California heavy oil at 13˚ API2. SMV is an abbreviation for Santa Maria Valley crude oil at 15˚ API
NYMEX Futures Strip Price as of March 31, 2012
Crude Oil Prices Natural Gas Prices
YearWTI @
CushingOklahoma
CurrentDifferentialMWSS (1)
vs WTI
CurrentDifferential
SMV (2)vs MWSS
SMVCrude OilForecast
NYMEXHenry Hub
Local GasPrice
Differential
Local Gas Price
$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
