Investor presentation April 2012


Published on

  • Be the first to comment

  • Be the first to like this

No Downloads
Total Views
On Slideshare
From Embeds
Number of Embeds
Embeds 0
No embeds

No notes for slide

Investor presentation April 2012

  1. 1. Underground Energy Corp.Unlocking Shale Oil Opportunities in California & NevadaTSX-V:UGECorporate PresentationOGIS April 2012
  2. 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 NevadaUnderground leases 1. Management estimates which also include a review by an internal qualified reservoir engineer 2
  3. 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, PAPeter 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 - Director33 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 - Director36 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 Companys management team and board of directors 3
  4. 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. 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 USSan 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. 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 billionVentura & 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. 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. 8. Monterey Shale Type Curves BOPD1000 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 Months1. Source: Occidental Petroleum Corporation, Minerals Management Service, DOGGR 8
  9. 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. 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 207To 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. 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 locationsPacific Kings County Tulare County  Initial 5 well drilling program commencedOcean 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 Barbara1. Management estimates which also include review by an internal qualified reservoir engineer 11
  12. 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. 13. Zaca Well Economics Zaca Field – All Historic WellsTypical Well All Wells Infill Wells Normalized Type Curve (61 wells) 250 Type Curve Type Curve 200Well Depth (MD feet) 5,500-7,500 4,500-6,500Dry Hole Well Costs ($M) $1,300-$2,000 $1,200-$1,800 150Completion Cost ($M) $200-$400 $200-$400 100Total Well Cost ($M) $1,500-$2,400 $1,400-$2,200 50UGE Interest (WI / NRI) 80% / 62.6% 80% / 62.6% 0 0 60 120 180 240 300 360Initial Prod Rate (BOPD) 205 70 Zaca Field – Infill Wells Drilled 1971 to PresentCum. Production (MBO) 535 375 Normalized Type Curve (18 wells) 250NPV @10% BT ($M)1 $ 11,325 $ 7,663 200IRR (%) 200% 85% 150Payback (years) 0.5 1.2 100 50 0 0 60 120 180 240 300 3601. Economics are internal estimates using NYMEX Futures Strip Prices as of March 31, 2012 with $14.74 deduction for diluent, gravity, location 13
  14. 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 $500Daily 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. 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 $1,000Daily 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. 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 KingsPacific County County currently being processedOcean  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 Barbara1. Source: GLJ Petroleum Consultants, effective date June 1, 2011 16
  17. 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 Reserves1Pacific 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 targets1. Source: GLJ Petroleum Consultants, effective date December 31, 2011 17
  18. 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. 19. GLJ Reserves Report December 31, 2011Reserves Category Gross (1) Net (2) Before Tax NPV 10 Mbbls (3) Mbbls (3) (thousands of US $) (5) (6) (7)Total Proved (1P) 566 445 $9,007Total Probable 1,479 1,161 $31,658Total Proved + Probable (2P) 2,045 1,606 $40,665Total Possible (4) 2,119 1,662 $40,938Total Proved + Probable + Possible (3P) 4,161 3,268 $81,603Notes:1. "Gross" reserves means Undergrounds working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Underground.2. "Net" reserves means Undergrounds working interest (operating and non-operating) share after deduction of royalty obligations, plus Undergrounds royalty interest in reserves.3. Totals for each category are reported on an "oil equivalent" basis which represents total light oil and heavy oil, in thousands of barrels of oil.4. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.5. The estimated future net revenues are stated before deducting future estimated site restoration costs and are reduced for estimated future abandonment costs and estimated capital for future development associated with the reserves.6. All future net revenue values calculated utilizing GLJ January 1, 2012 oil price forecast for WTI delivered into Cushing, OK corrected for oil gravity and local price differentials.7. It should not be assumed that the discounted future net revenues estimated by GLJ represent the fair market value of the reserves.8. This is a summary table, please refer to the press release dated April 10, 2012 for additional detail 19
  20. 20. Initial Exploration and Development Plan Activity 1Q12 2Q12 3Q12 4Q12 Net Cost ($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 $13.0Seismic Drilling Other 20
  21. 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) 500Daily 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. 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 exitCompany Monterey California management raised $25.5 ProductionInception Lease expertise team million 600+ bbls 2007 2008 2009 2010 2011 2012 22
  23. 23. Contact InformationUnderground Energy Corp. President & CEO – Mike Kobler3rd Floor mike.kobler@ugenergy.com7 W. Figueroa Street Phone: (805) 845-4700, x18Santa Barbara, CA,93101-5109 CFO – Peter Ballachey peter.ballachey@ugenergy.comTel: 805.845.4700 Phone: (805) 845-4700, x17Fax: COO – Bruce Berwager Phone: (805) 845-4700, x11 VP Corp Development – Simon Clarke Phone: (604) 551-9665 23
  24. 24. Cautionary and Forward Looking Statements AdvisoryUnderground 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 Companys proposed acquisition of oil and gas leases inCalifornia; (ii) the Companys 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
  25. 25. Notes to Disclosure1. 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 managements 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 managements 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. 26. Appendix
  27. 27. Management TeamMike 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 CaliforniaBruce 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 ResourcesPeter 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., CalgarySimon 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, AlaskaRandy Ray, Chief Geophysicist – BS, MS  36 years experience in Western US and an expert in integrated seismic and geological interpretation  Professional Geologist, Texas and WyomingKim 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. 28. Independent DirectorsRandy 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 LLCHarland 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 AlbertaAndrew 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 EnergySam 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. 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 1t2 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. 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. 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 2-18High 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 0.1-4Resource 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 1.5-11.7Emerging 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. 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 $4.50-5.501. 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. 32
  33. 33. Local Pricesbased on NYMEX Futures StripNYMEX 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
  1. A particular slide catching your eye?

    Clipping is a handy way to collect important slides you want to go back to later.