Domestically Building on Success in a Focused Core Area. Internationally Delineating Large Shale & Unconventional Resources

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1 Head Office: MADALENA VENTURES INC. Suite 200, 707-7th Avenue SW Calgary, Alberta, Canada T2P 3H6 International Office: MADALENA AUSTRAL SA 1209 Posadas, 5th Floor Buenos Aires, ARG C1011ABE MVN (TSX-V) Domestically Building on Success in a Focused Core Area Internationally Delineating Large Shale & Unconventional Resources

2 MADALENA: Corporate Overview Market capitalization ~$95mm (as at June 13, 2013); mm s/o (Basic) Strong balance sheet: positive working capital ~$12.4mm (as at Mar. 31, 2013) & undrawn debt facility Base production ~1,200 boe/d (43% oil & liquids) withadditional volumes tested, behind pipe and to be on-stream pending ongoing facility construction & pipeline de-bottlenecking. 2P reserves of 3.9 mmboe (46% oil and liquids) as of Dec. 31, 2012* Alberta, Western Canada +100,000 net acres(>150 net sections) strategically focused within the Greater Paddle River Core Area Large unbooked inventory of horizontal development locations Increasing production and reserves on three horizontal resource plays Neuquen Basin, Argentina +135,000 net acres(>210 net sections) across Three Blocks Focus on developing conventional sands and delineating shale resources Exposure to unconventional shale resources Ryder Scott Resource Report (Net to MVN -Dec. 31, 2012): Best Estimate TPIIP 34.8 billion BOE(51% Oil & NGLs)* * See Reader Advisories Best Estimate Total Contingent plus Prospective Recoverable Resources 2.9 billion BOE (45% Oil & NGLs)* 2

3 EXPERIENCED FULL-CYCLE OPERATING TEAM MANAGEMENT TEAM Kevin Shaw, P. Eng., MBA President & CEO Previously Managing Director & Head of Energy Research, Casimir Capital, Senior E&P Research Analyst and Partner, Wellington West Capital Markets Prior thereto, held various technical, senior management and/or officer roles with ExxonMobil (via Imperial Oil), Trimox Energy Inc., WorleyParsons. Thomas Love, CA VP, Finance & CFO Previously CFO, Online Energy Inc., CFO, Trimox Energy and Moxie Exploration and President & CEO, Moxie Petroleum Prior thereto with Westward Energy Ltd. and Charterhall Oil Canada, Articled at Clarkson Gordon & Co. (now Ernst & Young LLP) Steve Dabner, P. Geol. VP, Exploration Previously President and CEO, Online Energy Inc., President & CEO, Trimox Energy and Moxie Exploration and VP Exploration, Moxie Petroleum Prior thereto with Cimarron Petroleum Ltd. and Home Oil Company Ltd. Brent Foster, P. Eng. - VP, Engineering Previously VP, Engineering, Online Energy Inc., VP, Engineering & COO, Blue Mountain Energy Ltd. and VP, Engineering of a Private-co E&P Prior thereto with Rigel Oil and Gas Ltd., Home Oil Company Ltd, Santos Robert Stanton, P. Eng. - VP, Operations Previously VP, Operations, Online Energy Inc., VP, Engineering and Operations, Result Energy Inc. Prior thereto with Oiltec Resources Ltd., Pinnacle Resources Ltd., Jordan Petroleum Ltd., Transwest Energy Inc., Triton Canada Resources Ltd., Canadian Worldwide Energy Ltd. and Petro-Canada Inc. Ruy Riavitz Argentina Country Manager Previously E&P Manager, Hidenesa Gas SA (now GyP of Neuquen) & Independent Engineering Consultant Prior thereto Senior Consultant, PA Consulting, Reservoir Engineer, YPF BOARD OF DIRECTORS Raymond Smith, P. Eng. (Chairman) President, CEO & Director, Bellatrix Exploration Ltd. Barry Larson VP Operations & COO, Parex Resources Inc. Michael Lock President, Upsilon Holdings Ltd. Keith MacDonald President, Bamako Investment Management Ltd Jay Reid Partner, Burnet, Duckworth & Palmer LLP Ving Woo, P. Eng. VP, Engineering & COO, Bellatrix Exploration Ltd. Kevin Shaw, P. Eng., MBA 3

4 DOMESTIC ASSETS: Alberta, Canada Greater Paddle River Core Area (>150 Net Sections of Land) Three Key Resource Plays for horizontal multi-stage frac operations: Play #1: Ostracod - Development - 57 net sections -Oil Play #2: Notikewin/Wilrich - Development net sections -Liquids-rich gas Play #3: Nordegg - Emerging net sections -Oil & liquids-rich gas Additional opportunities exist across acreage in: Viking oil, Rock Creek oil, Duvernay shale Re-entry inventory on existing vertical wells Drill-Ready Program for ongoing horizontal drilling / fracing 4

5 GREATER PADDLE RIVER CORE AREA Strategically Focused GREENCOURT MAHASKA ALBERTA LEAMAN NITON PADDLE RIVER WILDWOOD WEST COVE EDMONTON BIGORAY 6 miles CALGARY 200 Gross Sections >150 Net Sections High W.I. Madalena Lands 100s Horizontal Locations Operated Lands Operated Infrastructure 5

6 RESOURCE PLAY #1: Ostracod Oil - Development 3 Madalena Hz Wells (100% WI) 12-5: 547 BOE/d (test) (¹) 8-5: 719 BOE/d (test) (²) 1-5: 307 BOE/d (IP30) 202 BOE/d (8 months) Husky Hz Well 4 Husky Hz Locations Long Run Hz Well Depth to Ostracod Madalena Lands Ostracod Oil Prospectivity Long Run Hz Location Ostracod Rights MVN Horizontal Locations 68 84% Gross Secs. Avg. W.I. 57 Net Secs. 6 miles Est. 50+ Horizontal Locations (¹)Average rate during final 24 hours of a production 5400 kpa; Sales production after accounting for shrinkage and NGLs recovery (38% oil & NGLs) (²)Average rate during final 24 hours of a production 1400 kpa; Sales production after accounting for shrinkage and NGLs recovery (46% oil & NGLs) 6

7 RESOURCE PLAY #1: Ostracod Oil - Type Well Economics Daily Average Production (boe/d) PADDLE RIVER OSTRACOD HORIZONTAL TYPE CURVE Madalena Months HIGH QUALITY OSTRACOD SANDSTONE OIL RESERVOIR TYPE CURVE ASSUMPTIONS Capital cost ($M) 3,600 EUR (Mboe) 290 F&D cost ($/boe) Netback ($/boe) Recycle ratio 2.41x IP30 (boe/d) 305 GOR (scf/bbl) 5000 NPV10% ($M) 2,961 IRR 51% Payout (years) 1.9 All amounts are based on internally generated management estimates prepared by a qualified professional engineer Price Deck = McD. Jan. 1/13 ($3.35/mcf & $87.50/bbl) adjusted for transportation & quality Ø = 13.7% k = 5.33 md 2.69 gm/cc 7

8 RESOURCE PLAY #2: Notikewin / Wilrich - Development Madalena 6-27 Notikewin Horizontal Tested 5.5 MMcf/d Raw Gas (¹) IP30 = 384 BOE/d (14% NGLs) Depth to Notikewin Madalena Lands UPPER WILRICH SANDS Notikewin Rights LOWER WILRICH SANDS 175 Gross Secs. NITON 77% Avg. W.I. NOTIKEWIN CHANNEL TRENDS WILDWOOD 6 miles 136 Net Secs. Regionally Stacked Mannville Trends Focused on Notikewin & Wilrich Est Horizontal Locations 28 to 35 bbls/mmcf (¹)Average raw gas production 3000 kpa over the final 24 hours of a production test 8

9 RESOURCE PLAY #2: Notikewin / Wilrich - Type Well Economics Daily Average Production (mcfe/d) NITON NOTIKEWIN HORIZONTAL TYPE CURVE Months MVN (100% WI) NITON NOTIKEWIN VERTICAL PRODUCER TYPE CURVE ASSUMPTIONS Capital cost ($M) 3,800 EUR (Mboe) 504 F&D cost ($/boe) 7.55 Netback ($/boe) Recycle ratio 2.24x IP (30 day average -mcfe/d) 3,248 LGR (bbl/mmcf) 28 NPV10% ($M) 2,596 IRR 34% Payout (years) 2.8 All amounts are based on internally generated management estimates prepared by a qualified professional engineer Price Deck = McD. Jan. 1/13 ($3.35/mcf & $87.50/bbl) adjusted for transportation & quality RAW GAS (to: Mar. 2013) CUM: 535 mmcf CUR: 105 mcf/d 22m Net Pay 9

10 RESOURCE PLAY #3: Emerging Nordegg Oil & Liquids-Rich Gas Depth to Nordegg GREENCOURT Madalena Lands Nordegg Rights LEAMAN PADDLE RIVER 183 Gross Secs. 80% Avg. W.I. WILDWOOD 146 Net Secs. NORDEGG RESOURCE + 55 MM BOE of Oil and LIQUIDS-RICH GAS PRODUCED TO DATE BIGORAY Madalena Horizontal 6 miles Nordegg Resource Widespread across Madalena Lands Liquids-rich with Vertical Producers at >100+ bbls/mmcf Inventory of Horizontal Locations Initial Focus Wildwood Area 10

11 RESOURCE PLAY #3: Emerging Nordegg Oil & Liquids-Rich Gas - Type Well Economics Daily Average Production (mcfe/d) WILDWOOD NORDEGG HORIZONTAL TYPE CURVE OFFSETTING WILDWOOD NORDEGG VERTICAL PRODUCER (MVN 0% WI) 6% SS Ø Months -ON-STREAM: SEPT NORDEGG TYPE CURVE ASSUMPTIONS Capital cost ($M) 3,700 EUR (Mboe) 621 F&D cost ($/boe) 5.96 Netback ($/boe) Recycle ratio 3.02x IP30 (boe/d) 959 LGR (bbl/mmcf-sales) 130 NPV10% ($M) 5,044 IRR 131% Payout (years) 1.0 All amounts are based on internally generated management estimates prepared by a qualified professional engineer Price Deck = McD. Jan. 1/13 ($3.35/mcf & $87.50/bbl) adjusted for transportation & quality 13m Net Pay PEKISKO To: Mar GAS OIL H2O BOE CUM: 1,328 mmcf 57,302 bbls 108,333 bbls 278,630 boe CUR: 216 mcf/d 24 bopd 20 bwpd 60 boepd 11

12 DUVERNAY SHALE: Exposure on 100+ Net Sections DUVERNAY WEST SHALE BASIN: OVERVIEW MADALENA DUVERNAY LANDS >100 Net Sections (100% WI) KAYBOB AREA Edmonton 24 miles PEMBINA AREA Source: Geological Atlas of the Western Canadian Sedimentary Basin Figure 31.7: The occurrence and maturity of the Duvernay source facies in the Western Canadian Sedimentary Basin Recent Industry Duvernay Wells 12

13 INTERNATIONAL ASSETS: Neuquén Basin, Argentina Strategically working to unlock value from shale & unconventional resources..while developing conventional reservoirs Three large land blocks with stacked Conventional & Unconventional plays 279,642 gross acres (437 sections) 134,968 net acres (210 net sections) Well positioned in both the shale oil and shale gas windows Conventional development drilling combined with resource delineation Ryder Scott Resource Report (Dec. 31, 2012) Evaluation of Resources net to Madalena s Interest on all three blocks: Best Estimate TPIIP 34.8 billion BOE(51% Oil & NGLs)* Best Estimate Total Contingent plus Prospective Recoverable Resources * See Reader Advisories 2.9 billion BOE (45% Oil & NGLs)* 13

14 MVN S NEUQUÉN ACREAGE - Three Large Land Blocks Surrounded by Major E&Ps CURAMHUELE(90% WI) Partner: GyP (10%) 56,216 Gross acres (50,594 Net acres (79 Net sections)) CORTADERA(40% WI) Partners: Apache (50%)& GyP (10%) 123,503 Gross acres (49,401 Net acres (77 Net sections)) COIRON AMARGO(35% WI) Partners: Roch(10% Op.), Apco(45%) & GyP (10%) 99,923 Gross acres (34,973 Net acres (54 Net sections)) New entrants have farmed-in or acquired existing blocks in order to build meaningful acreage positions: 20 km 14

15 CONTINGENT + PROSPECTIVE RECOVERABLE RESOURCES * - Net to MVN by Block CONTINGENT RECOVERABLE RESOURCES (C2 Best Estimate) BLOCK FORMATION Oil & NGLs (MMbbl) Nat. Gas (Tcf) Oil, NGLs & Nat. Gas (MMBOE) Coiron Amargo Vaca Muerta PROSPECTIVE RECOVERABLE RESOURCES (Best Estimate) Coiron Amargo Vaca Muerta Total Coiron Amargo Curamhuele Lower Agrio Vaca Muerta ,157 Total Curamhuele ,530.6 Cortadera Basal Quintuco Vaca Muerta Total Cortadera ,048.9 TOTAL , BILLION bbl of Recoverable Oil & NGLs TRILLION cf of Recoverable Natural Gas BILLION BOE Recoverable * See Reader Advisories 45.2% Oil & NGLs 15

16 RYDER SCOTT RESOURCE REPORT SUMMARY * TOTAL ON ALL THREE BLOCKS NET TO MVN: Tabulated for the Lower Agrio, Basal Quintuco & Vaca Muerta zones only TPIIP Oil & NGLs (MMbbl) Nat. Gas (Tcf) Oil, NGLs & Nat. Gas (MMBOE) P90 P50 P10 P90 P50 P10 P90 P50 P10 Lower Agrio 3, , , , , ,741.2 Basal Quintuco , , ,018.6 Vaca Muerta 10, , , , , , , , , , , , BILLION BOE In-Place CONTINGENT + PROSPECTIVE RECOVERABLE RESOURCES Oil & NGLs (MMbbl) Nat. Gas (Tcf) Oil, NGLs & Nat. Gas (MMBOE) 1C/Low 2C/Best 3C/High 1C/Low 2C/Best 3C/High 1C/Low 2C/Best 3C/High Lower Agrio Basal Quintuco Vaca Muerta , , , , , , , ,223.8 TOTAL VACA MUERTA: MILLION bbl of Recoverable Oil & NGLs * See Reader Advisories TRILLION cf of Recoverable Natural Gas BILLION BOE Recoverable 47.8% Oil & NGLs 16

17 VACA MUERTA SHALE Throughout All Three Blocks Vaca Muerta Shale: Thickness up to 700m+ and gets deeper & thicker from east to west in the basin Thickness >1000m with the inclusion of the overlying Quintuco Vaca Muerta is Oil proneat Coiron Amargo, Gas prone around the Cortadera block and Oil, Liquids & Gas prone at Curamhuele given it is located across a transition zone (maturity is based on vitrinite reflectance values) CURAMHUE CURAMHUELE LE CURAMHUELE CORTADERA COIRON AMAR CORTADERA GO COIRON AMARGO COIRON AMARGO Quintuco/Vaca Muerta Net I sopach Quintuco/Vaca Muerta Net Isopach 20 km 20 km VACA MUERTA/QUINTUCO THICKNESS VACA MUERTA SHALE MATURITY 17

18 BLOCK #1: COIRON AMARGO Vaca Muerta - Big Oil & Big JVs MADALENA: 35% WI Recent publicly disclosed developments: YPF discovers ~1 Billion Boe atloma La Lataover 428 km 2 area (5.6 mmboe/section) in the Vaca Muerta shale Chevron signs $1.5 Billion MOU for Vaca Muerta development with YPF at Loma La LataNorte & Loma Campanablocks for 50% W.I.; Initial 100 well unconventional program with up to US $15 Billion in drilling to follow with potential for wells to develop the field (announced Dec. 2012, upsized in May 2013) Bridassigns $1.5 Billion MOU for Vaca Muerta development involving a 2 year plan to drill 130 shale wells at Bajadade Anelo and Bandurria blocks to end up with 35% and 24.5 % W.I. respectively (announced Dec. 2012) 20 km Vaca Muerta Shale -Gross thickness meters -All wells encountered oilin Vaca Muerta -Oil production surrounding block -Loma La Lata, BP 2 & 7 wells -Two Vaca Muerta shale plays : 1) Regional 2) Naturally Fractured - Successful CAS X-1 Workover recently completed -Shell horizontal: Vaca Muerta 500m horizontal (w/5 fracs) tested 465 bopd (35⁰ API) 18

19 BLOCK #1: COIRON AMARGO - MVN: 35% WI Operations COIRON AMARGO NORTE Sierras Blancas (Conventional oil) Northern portion (108 km 2 ) converted to 25-year exploitation license 6 light oil discoveries to date and upcoming horizontal development Successful recent workover at CAN x-3 Upcoming horizontal re-entry at CAN x-2 Additional horizontal well inventory on multiple structures COIRON AMARGO SUR Vaca Muerta (Unconventional oil) Successful recent workover at CAS x-1 2 upcoming 3D seismic programs commencing in Q2 Upcoming Vaca Muerta shale exploration wells (Initially CAS x-14 & CAS x-15) Shell drilling offsetting Vaca Muerta shale horizontals Contingent Recoverable Resources (C2 Best Estimate)* CAS x-5 CAS x-15 FORMATION Oil & NGL s (MMbbl) Nat. Gas (Tcf) Oil, NGL s & Nat. Gas (MMBOE) CAS x-1 Vaca Muerta Prospective Recoverable Resources (Best Estimate)* Vaca Muerta Total Contingent + Prospective* CAS x-14 * See Reader Advisories 19

20 BLOCK #2: CURAMHUELE MVN: 90% WI (Operated) High-ImpactAgrio shale, Vaca Muerta shale&mulichinco plays Agrio shale to be evaluated in the CH.x-1 vertical well -Originally flowed ~150 bopdwithout frac/stimulation Mulichincoto be evaluated in the Yp.x-1001vertical well offsetting Yp.x-1stthat production tested after acidizing 10 mmcf/d of gas and 500 bbl/d of 51ºcondensate CURAMHUELE Majors including ExxonMobil and Total drilling nearby Public Vaca Muerta results: Americas Petrogas/ExxonMobil: Los ToldosII: IP 694 bopd (40⁰ API) Los ToldosI: IP 3.2 MMcf/d + 18 bbl/d (54-58⁰ Condensate) Prospective Recoverable Resources (Best Estimate)* FORMATION Oil & NGLs (MMbbl) Nat. Gas (Tcf) Oil, NGLs & Nat. Gas (MMBOE) 20 km Lower Agrio Vaca Muerta ,157.6 Total Curamhuele ,530.6 * See Reader Advisories 20

21 BLOCK #3: CORTADERA MVN: 40% WI Madalena 40% W.I.; Partnered w/ Structure Map: Top Tordillo (Base of Vaca Muerta) CorS.X-1 Deep Test cased to 4,500 m for both tight unconventional plays and shale gas 1. Total Quintuco/Vaca Muerta: 1097m thick Vaca Muerta : 520m thick Quintuco : 577m thick 2. Mulichinco: 206m thick 3. Agrio tight sands Two stage frac conducted in Vaca Muerta shale Vaca Muerta shale gas resource Upholezones (i.e. stacked on top of Vaca Muerta source rock) to be evaluated Prospective Recoverable Resources (Best Estimate)* FORMATION Oil & NGLs (MMbbl) Nat. Gas (Tcf) Oil, NGLs & Nat. Gas (MMBOE) CorS.x-1 Basal Quintuco Vaca Muerta Total Cortadera ,048.9 * See Reader Advisories 10 km 21

22 MADALENA (MVN TSX-V) Activity & Catalysts for Growth Canadian Assets Greater Paddle River Core Area Progress being made on all 3 primary resource plays (Ostracod, Notikewin and Nordegg) Q2 focused on bringing Ostracod behind-pipe production volumes on-stream H program includes multi-well horizontal activity with oil & liquids-rich gas focus Follow-up on Ostracod oil success with additional hztls Continue evaluation on emerging Nordegg liquids-rich gas play Test conventional Nordegg & Viking oil plays Domestic strategy to continue to increase production, reserves & cash flow Argentina Assets Coiron Amargo, Curamhuele & Cortadera Completed detailed technical evaluation, review & assessment of shale, unconventional resources & tight sand plays across all three blocks 2013 Coiron Amargo Program includes workovers, high impact Vaca Muerta shale drilling, horizontal development activity and 3D seismic Curamhuele Assess strategic partnering in 2013 to advance high impact Lower Agrio shale and Mulichinco tight sand plays (Potential re-entries of CH.x-1 and YP.x-1001) and Vaca Muerta; Cortadera Conduct possible re-entry at CorS.x-1 location to evaluate uphole zone(s) of interest 22

23 APPENDIX # 1: Argentina s Shale Potential June 2013 EIA Released Updated World Shale Oil & Gas Assessment Argentina has 4th largest technically recoverable shale oil resource in the world Behind only Russia, USA & China 3X greater than Canada Argentina has 2nd largest technically recoverable shale gas resource in the world Behind only China 1.2X greater than USA 1.4X greater than Canada Three Shale Plays in Argentina: Vaca Muerta,Agrio,Los Molles Neuquén Basin is a the focus of Shale Resource development by Major E&Ps and NOCs 23

24 APPENDIX # 2: Lower Agrio Shale Lower Agrio Shale Within the oil generation window 250+ meters thick across Curamhuele block Yp.x-1001 well at Curamhuele flowed minor amounts of oil without frac/stimulation CH.x-1 well at Curamhuele flowed ~150 bopd (¹)without frac/stimulation -to be further evaluated Lower Agrio Shale zone is continuous & consistent throughout the Curamhuele block and is present in adjacent wells Multiple sections within Agrioto be tested Layered and brittle Expected to be ideal to fracture Horizontal multi-stage frac potential CORTADERA CURAMHUELE Shale Basin 25 km C.I. = 25 m (¹)Average rate over a 30 hour production test 24

25 APPENDIX # 3: Mulichinco Zone Mulichinco Play Rapid thickening (200+ meters) of Mulichinco on the Cortadera and Curamhuele blocks Liquids-rich tight sands play Mulichincoto be evaluated in the Yp.x-1001well (500m north of Yp.x-1st) Management believes significant potential exists on this conventional tight sands play Mulichinco Reservoir Mulichinco to be evaluated in Yp.x-1001 Mulichinco tested 10 mmcf/d in Yp.x-1st Existing liquids-rich gas discovery on Curamhuele block Historical production test at Yp.x-1stafter acidizing yielded 10 mmcf/d of gas and 500 bbls/d of 51º condensate from upper portion Management believes there is significant horizontal development potential in the lowermost and coarser clastic part of Mulichinco deposited during an initial low-stand period Chihuidos Anticline High mud gas readings Correlation GR 0 API 200 SP -100 MV 50 CALI 6 IN 16 DRHO(N/A) Sandstone in CorS.x-1 Depth MD Quintuco Resistivity Gas ResS ResM KG/MT 2898 ResD US/MT 90 TGAS(N/A) B/E 20 C4(N/A) Curamhuele Mulichincoin these wells Porosity PHIN RHOB DT PEF Permeability 25 km Production from the Mulichinco& Basal Sands ~1 TCF plus liquids in Sierra Chatafield Lower Agrio Mud gas readings rose by 2 orders of magnitude at the top of the Mulichinco Mulichinco Mulichinco Low-stand 25

26 READER ADVISORIES The information in this document contains certain forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forwardlooking statements are often, but not always, identified by the use of words such as "seek","anticipate","plan","continue","estimate","approximate","expect","may","will","project","predict","potential","targeting", "intend","could","might", "should","believe","would" and similar expressions. In particular, this document contains forward-looking statements pertaining to resources of Madalena and other oil and gas information. These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Madalena's control, including: the impact of general economic conditions; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions, of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and obtaining required approvals of regulatory authorities. Madalena's actual results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits Madalena will derive from them. These statements are subject to certain risks and uncertainties and may be based on assumptions that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. The forward-looking statements in this document are expressly qualified in their entirety by this cautionary statement. Except as required by law, Madalena undertakes no obligation to publicly update or revise any forward-looking statements. Investors are encouraged to review and consider the additional risk factors set forth in Madalena's Annual Information Form, which is available on SEDAR at All calculations converting natural gas to barrels of oil equivalent ("boe") have been made using a conversion ratio of six thousand cubic feet (six "Mcf") of natural gas to one barrel of oil, unless otherwise stated. The use of boe may be misleading, particularly ifused inisolation,astheconversionratioofsixmcfofnaturalgastoonebarrelofoil isbasedonanenergyequivalencyconversionmethodprimarilyapplicableattheburnertipanddoesnotrepresentavalueequivalencyatthewellhead. Given thatthevalue ratiobasedonthecurrentpriceofcrudeoil ascomparedtonaturalgasissignificantly differentfromtheenergyequivalency of6:1,utilizing aconversionona6:1basismaybemisleading asanindication ofvalue. Certain information in this document may constitute"analogous information" as defined in National Instrument Standards of Disclosure for Oil and Gas Activities("NI "), including, but not limited to, information relating to the areas in geographical proximity to prospective lands held by Madalena and production information related to wells that are believed to be on trend with Madalena's properties. Such information has been obtained from government sources, regulatory agencies or other industry participants. Management of Madalena believes the information is relevant as it helps to define the reservoir characteristics in which Madalena may hold an interest. Madalena is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor. Such information is not an estimate of the reserves or resources attributable to lands held or to be held by Madalena and there is no certainty that the reservoir data and economics information for the lands held or to be held by Madalena will be similar to the information presented herein. The reader is cautioned that the data relied upon by Madalena may be in error and/or may not be analogous to such lands to be held by Madalena. Any references in this document to test rates, flow rates, initial and/or final raw test or production rates, early production, test volumes behind pipe and/or"flush" production rates are useful in confirming the presence of hydrocarbons, however, such rates are not necessarily indicative of long-term performance or of ultimate recovery. Such rates may also include recovered"load" fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for Madalena. In addition, the Vaca Muerta shale is an unconventional resource play which may be subject to high initial decline rates. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Under NI , the methodology to be used to calculate finding and development costs includes incorporating changes in future development capital required to bring the proved undeveloped and probable reserves to production. Changes in future development capital have been taken into account in these calculations. In this document, FD&A costs have been calculated prior to eliminating the effects of acquisitions and dispositions. After eliminating the effects of acquisitions and dispositions, finding and development costs for the year ended December 31, 2012 are $18.86/boe on P+P reserves and $32.60/boe on proved reserves for the Company's Canadian assets; such finding and development costs were calculated in accordance with NI using the following two methods:(1): adding exploration and development costs incurred in the most recent financial year with the change during the most recent financial year in estimated future development costs relating to proved reserves and dividing that sum by additions to proved reserves during the most recent financial year; and(2) adding exploration and development costs incurred in the most recent financial year with the change during the most recent financial year in estimated future development costs relating to proved reserves and probable reserves and dividing that sum by additions to proved reserves and probable reserves during the most recent financial year. While NI requires disclosure of certain comparative information for the three most recent financial years when disclosing finding and development costs, due to the fact that Madalena's recent acquisition of Canadian assets occurred just prior to year-end in 2012, if such information was provided it could be misleading, as it would be comparing significantly different asset bases. Notes To Disclosure of Resources: (1) "Total Petroleum Initially In Place" means DPIIP + UPIIP. When calculating DPIIP, there is no material production or reserves associated with these properties. Contingent resources is the only category of DPIIP that has been categorized as recoverable. Prospective resources is the only category of UPIIP that has been categorized as recoverable. There is no certainty that it will be commercially viable to produce any portion of the contingent resources referred to in the tables above. There is no certainty that any portion of the prospective resources referred to in the tables above will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of these resources. (2) Certain volumes are arithmetic sums of multiple estimates of contingent& prospective resources, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of resources and appreciate the differing probabilities of recovery associated with each class as explained herein. Details on the categories that comprise these calculations areinthetablesthatfollow. 26

27 READER ADVISORIES Coiron Amargo Discovered Petroleum Initially In Place (1) (net to Madalena) Oil, NGLs and Natural Gas at December 31, 2012 Notes: (1) There is no certainty that it will be commercially viable to produce any portion of the resources referred to in the table above. 27

28 READER ADVISORIES DEFINITIONS: "Contingent resources" Definition: Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. "Discovered petroleum initially-in-place" or "discovered resources" or "DPIIP" Definition: That quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially-in-place includes production, reserves and contingent resources; the remainder is unrecoverable. "Prospective resources" Definition: 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. "Total petroleum initially-in-place", "total resources" or "TPIIP" Definition: That quantity of petroleum that is estimated to exist originally in naturally occurring accumulations; equal to DPIIP plus UPIIP. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. "Undiscovered petroleum initially-in-place", "undiscovered resources" or "UPIIP" Definition: That quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially-in-place is referred to as prospective resources; the remainder is unrecoverable. Kevin Shaw President and Chief Executive Officer (ext 230); kdshaw@madalena-ventures.com 28