Cano Petroleum 8-K/A Investor Presentation Investor Presentation January, 2008 January, 2008

Exhibit 99.1

Investor Presentation Investor Presentation January, 2008 January, 2008

Disclosure Statements Disclosure Statements Safe-Harbor Statement -- Except for the historical information contained herein, the matters set forth in this presentation are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The company intends that all such statements be subject to the “safe-harbor” provisions of those Acts. Many important risks, factors and conditions may cause the company’s actual results to differ materially from those discussed in any such forward-looking statement. These risks include, but are not limited to, estimates or forecasts of reserves, estimates or forecasts of production, future commodity prices, exchange rates, interest rates, geological and political risks, drilling risks, product demand, transportation restrictions, the ability of Cano Petroleum, Inc. to obtain additional capital, and other risks and uncertainties described in the company’s filings with the Securities and Exchange Commission. The historical results achieved by the company are not necessarily indicative of its future prospects. The company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Cautionary Notes to Investors – The Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Cano uses “non-proved reserves” in this presentation, which the SEC’s guidelines strictly prohibit it from including in filings with the SEC. Investors are urged to also consider closely the disclosures in Cano’s Form 10-K for the fiscal year ended June 30, 2007 and Cano’s Form 10-Q for the fiscal quarter ended September 30, 2007, available from Cano by calling 877.698.0900. These forms also can be obtained from the SEC at www.sec.gov . PV10 Calculations of Reserve Values are based on the SEC price deck for June 30, 2007 (Cano’s fiscal year end) of $70.47 per bbl and $6.40 per mcf, are calculated “before tax” (BT) and consider the anticipated costs to develop and produce.

Cano Business Model Cano Business Model Market World demand strong and growing Supply issues Favorable economics Early Mover Business model established Team and relationships built Asset accumulation Minimal Competition to Date Secondary and Enhanced Oil Recovery Managed Risk No exploration risk No international or offshore risk Limited engineering risk

Listing AMEX: CFW Senior Debt:(~$60 million Borrowing Base) $44.0 million Drawn Cash $1.8 million Preferred Convertible Stock $44.5 million Shares outstanding 37.3 million Market Cap $277 million Pre-Tax PV-10 $1,138 million Proved Reserves 66.7 MMBOE % PUD 83% % Oil 64% Total Acreage 73,000 Areas of Operation TX Panhandle, Central TX, OK and NM Cano Petroleum Cano Petroleum – Key Statistics Key Statistics (b) (a) Total diluted shares outstanding of 39.8 million (less Pref). (b) Market Cap as of Jan 2008, based on stock price of $7.50 and 37.0 million shares outstanding. (c) Based on SEC Price Deck for June 30, 2007 of $70.47/Bbl and $6.40/Mcf. (c) (a)

Historical Trends Historical Trends MBOE Reserve Growth *CAGR = 680% $M PV–10 Growth *CAGR = 827% Production Growth MBOE *CAGR = 572% *Compounded Annual Growth Rate 0 100 200 300 400 500 600 2004 2005 2006 2007 $0 $200 $400 $600 $800 $1,000 $1,200 2004 2005 2006 2007 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 2004 2005 2006 2007

Summary FY 2007 Summary FY 2007 Major Accomplishments Major Accomplishments • Drilled 80 wells • Added ~ 22.4 MMBOE proved reserves at $2.38/BOE F&D • Barnett Shale gas field discovery adding ~ 11MM BOE and $30MM in PV-10 • Cato Field acquisition adding ~ 9MM BOE and ~ $116MM in PV-10 (less than $1/BOE acquisition cost) • $7MM Rich Valley asset sale ($3.4MM after-tax gain) • Panhandle Field new gas contract: -adding ~ $125M/month revenue -adding ~ $150MM in PV-10 of proved reserves • Strengthened Board and Management Team •Production up 84% over prior year •Revenue up 79% over prior year •Proved Reserves up 47% over prior year

Why Enhanced Oil Recovery Why Enhanced Oil Recovery • Proven, low risk technology – Original Oil in Place (OOIP) determined by historical production • Focus on mature fields with substantial existing infrastructure – Legacy infrastructure and abundant technical information • Experienced management and technical team provide Cano with a competitive advantage – Large Independents and Majors less focused on mature fields • Large-scale projects with substantial reserve potential – Primary recovery only represents 10% - 30% of OOIP

15% to 25% Additional Recovery of OOIP (Tertiary Recovery) 10% to 20% Additional Recovery of OOIP (Secondary Recovery) 10% to 30% Recovery of OOIP (Primary Recovery) Secondary Tertiary 25% to 65% Residual Recovery Profile of a Conventional Reservoir

Davenport Acreage: 2,178 1.5 MMBOE proved; 11 MMBOE probable 70 boepd Production & Reserves Production & Reserves Total Reserves Total Acreage: ~77,000 MMBOE PV10 SEC proved (6/30/07) 67 $1,138 MM Prob/Poss (Unrisked)* 118 $1,307 MM Nowata Acreage: 2,601 1.7 MMBOE proved; 5 MMBOE probable 235 boepd FT. WORTH DAVENPORT DESDEMONA CORSICANA NOWATA Corsicana Acreage: 341 .2 MMBOE proved; 1.0 MMBOE probable Desdemona Acreage: 11,068 Duke Waterflood: 1.0 MMBOE proved; 27 MMBOE prob/poss 20 boepd Barnett Shale: 11 MMBOE proved 150 boepd Panhandle Acreage: 27,000 35.5 MMBOE proved; 45 MMBOE prob/poss 610 boepd Pantwist Acreage: 9,700 6.8 MMBOE proved; 3 MMBOE prob/poss 330 boepd PANTWIST Cato Field, Chavez & Roosevelt Counties, NM Acreage: ~20,000 100 boepd 9 MMBOE proved; 26 MMBOE prob/poss Total Production: ~ 1,515 boepd Oct.-07 Actual Production CATO PANHANDLE

EOR Capture by Asset EOR Capture by Asset Cano Petroleum Unrisked Reserve Profile OOIP (MMBOE) Primary Secondary Tertiary Total Corsicana -ASP 7 2 1 1 4 Percentage of OOIP 98 29% 14% 14% 57% Cato - Waterflood+ CO-2 15 25 10 50 Percentage of OOIP 15% 26% 10% 51% Davenport - ASP 58 12 10 11 33 Percentage of OOIP 21% 17% 1S% 57% Desdemona Barnett Shale 15 92 11 11 Desdemona Waterflood+ASP 24 9 19 52 Percentage of OOIP 26% 10% 21% 57% Nowata -ASP 58 18 15 5 38 Percentage of OOIP 382 30% 26% 9% 65% Panhandle - Waterflood + CO-2 90 52 24 166 Percentage of OOIP 24% 14% 6% 43% Pantwist - Waterflood 161 22 9 31 Percentage of OOIP 14% 6% 19% PDP/PDNP 9 9 Total Portfolio 871 203 121 70 394 MMBOE 23% 14% 8% 45% Cano Capture 20 95 70 185 Percentage of OOIP 2% 11% 8% 21% Memo: 06/30/2007 Proved Reserves 20 46 1 67

Typical EOR Project Timeline Typical EOR Project Timeline Phases Duration • Lab Research or Simulation • Well Re-Drills, Facilities in Place • Water Injection – Initial Response • Production Reaches Peak • Peak Production Plateau • Production Decline 3 – 6 Months 6 – 12 Months 6 – 9 Months 3 Years 4 Years 10 – 30 Years

Proved Reserves by Project (a) PV-10 by Project (b) FY 2007 Proved Reserves and PV FY 2007 Proved Reserves and PV-10 10 (a) Proved Reserves as of June 30, 2007. (b) PV-10 based on SEC Price Deck for June 30, 2007 of $70.47/Bbl and $6.40/Mcf. Project Proved Reserves (MMBOE) (a) Cato 9.1 Panhandle 35.5 Pantwist 6.8 Desdemona 11.9 Nowata 1.7 Davenport 1.5 Corsicana 0.2 Cano Total 66.7 MMBOE Project PV-10 ($MM) (b) Cato 116.0 Panhandle 867.0 Pantwist 73.0 Desdemona 41.0 Nowata 18.5 Davenport 18.0 Corsicana 4.5 Cano Total $1,138 MM 10% 75% 7% 2% 0% 4% 2% 13% 54% 10% 3% 18% 0% 2% Cato Panhandle Pantwist Desdemona Nowata Davenport Corsicana

FY 2007 Proved Reserves FY 2007 Proved Reserves PV PV-10 Reconciliation ($MM) 10 Reconciliation ($MM) 2006 YE 2007 YE $30 $116 ($100) $150 ($35) $57 $350 All Other Cato Acquisition Barnett Shale New Gas Contract PH LOE PH PUD Revisions PH Acceleration Total Panhandle Revisions +$457 MM

14 Panhandle Regional Profile Panhandle Regional Profile • Area is surrounded by precedent successful secondary recovery pr Area is surrounded by precedent successful secondary recovery projects • Analog recovery response model was developed based on the Analog recovery response model was developed based on the adjacent East Schafer Ranch Waterflood project East Schafer Ranch Waterflood project Cockrell Ranch Waterflood East Sch afer Ranch Waterflood Cano Leas es Anal og Secondary Recovery Projects

15 Acceleration Plan: Acceleration Plan: Equity Raise Use of Proceeds Equity Raise Use of Proceeds • Accelerate Harvey Development FY Accelerate Harvey Development FY 2008 2008 • Accelerate Mobil Accelerate Mobil-Fee Lease Fee Lease Development Development (25 new wells drilled in FY 2008) (25 new wells drilled in FY 2008) • Aggressively Pursue Acquisition Aggressively Pursue Acquisition Acreage Acreage • Move Production Responses from Move Production Responses from late late-2009 into late 2009 into late-2008 calendar year 2008 calendar year Panhandle Field Development Panhandle Field Development Harvey Harvey Cockrell Ranch Cockrell Ranch Cooper Cooper Mobil Fee Mobil Fee Schafer Ranch Schafer Ranch

Waterflooding 101 Waterflood Response is a function of the amount of water injected •The amount of water injected is measured in Pore Volumes or PVI •Each reservoir has a response range (P-90,P-50,P-10) based on PVI •Typically, initial reservoir responses are seen between .10 to .20 PVI •Typically, project confirmation is seen at .40 PVI •Actual Cumulative Production is plotted versus the calculated response curves to determine the relationship to: • P-90 Proved Reserves • P-50 Probable Reserves • P-10 Possible Reserves * * * ** * * * * * * * * * * * * * Actual * *

Cockrell Ranch Waterflood Development Status Report Cockrell Ranch Waterflood Development Status Report Cockrell Ranch Phase III Late November, 2007 21 Injectors=14,700 BWIPD 21 Producers Cockrell Ranch Phase III January, 2008 21 Injectors=14,700 BWIPD 21 Producers

Cockrell Ranch Waterflood Response 3 1 2 9 1 7B 9C 11 9 4 5 E3 E1 1 1 7 8 13 18 19 20 21 12 8 6 8 2 1 2 4 4 56 61 70 71 A33 A34 A35 36 101 47 37 57 88 96 97 98 99 46 3-A 37 59 4 4 5 5 34 35 102 3 11 11 12 100 10 10 10 3 3 2 8 4 5 6 24 7 60-G 11 B4 1 2 14 18 2 7 E 7 21 31 A31 A32 6 1 6 8 8 12 6 1 5 6 6 6 7 3 5 1 1 7 2 2 3 3 3 3 8 73 4 72 74 76 77 78 79 83 104 58 8 9 9 103 13 B5-G 5 5 8 8-A 7 19 30 49 50 2 4 5 27 29 16 17 48 15 68 69 75 80 82 65 51 39 40 41 42 43 44 45 67 50 66 52 53 54 55 62 63 64 49 32 38 B23 19 B19 20 B20 22 B21 17 B 22 B16 24 25R 26 27 28 29 30 23 33 18 10 11 12 13 14 15 91 92 93 95 7 1 94 B24 B25 B1 B2 B3 3 7 6 B6 B7 B8 B9 10 20 9 3-A 6 9 89 90 1 85 5 B13 B10 87 B12 86 B14 B15 B17 B18 B26 81 84 B 11 1 106 105 WSW 16 2R 35R 31R 47R 1R 36R 74R 2R 43R 9R 96R 71R 60-GR 37R 102R 97R B4R B7R B8R B9R B10R B12R B13R B15R B18R B19R B21R B23R E1R E 7R 4R 8R 9R 10R 11R 12R 17R 18R 20R 21R 22R 23R 24R 39R 40R B24R 26R 41R 52R 28R B17R A33R 32R A31R B22R II III I Cockrell Ranch Pore Volume Bubble Map December 12, 2007 1, 732,866 Bbls Cum Water FEE T0 5001, 0001, 500 ATTRIBUT E MAP Zone: WATERFLOOD - FLOO D_RESPONSE [ AJK] I S PRESENT REMARKS Fo r: Pat McKinn ey 6 60 ft. = .2 5 p v. By: Mar t ing & Ki mble PE T RA 1 1/ 27 /2 0 7 1: 21 :4 2 PM Pre-Response Seen at 10 Wells Meaningful Response Expected Radial Injection

Potential Panhandle “Bolt-On” Acquisitions A- 846 A-449 A-77 A- ? A-728 A-679 A-705 A- 65 A- 294 A- 44 A-709 A-307 A-1225 A-78 A-1218 A- 295 A-445 A- 642 A-641 A-1140 A- 1022 A-605 A- 1244 A- 141 A-308 A- 748 A-664 A-297 A-1020 A- 417 A- 681 A-443 A-442 A-439 A-296 A- 435 A-819 A- 282 A- 281 A- 451 A-648 A- 649 A-778 A- 300 A - 10 18 A- 1101 A- 1034 A- 943 A-400 A-1203 A- 1206 A- 315 A -2 79 A -3 01 A- 16 9 A- 10 3 3 A-436 A- 466 A- 128 A- 739 A- 79 6 A-740 A - 78 1 A-298 A -2 83 A -2 80 A-6 69 A- 29 9 A -1 68 A -9 42 A - 67 0 A- 4 46 A -7 80 A- 43 8 A-287 A -8 91 A- 797 A- 27 8 A -7 1 4 A -3 32 A -3 3 0 A-1009 A- 41 A- 907 A -7 94 A - 27 5 A -1 2 8 A -7 93 A- 2 76 A- 3 31 A -3 3 3 A -8 9 2 A- 10 1 5 A- 40 7 4 73 61 HOUST ON EAS T A ND TEXA S WES T RA ILROAD 19 11 BLK Z 5 10 RAILROAD NTRAL 71 1 6 7 2 21 BLK 46 7 8 6 9 2 AND R ED RAILROAD EA ST LINE RIV ER 13 14 7 9 15 3 1 TEXAS CE NTR AL 8 D & S E RR RAILROAD 14 10 12 11 6 5 6 B LK B4 13 1 29 13 12 5 4 D S & E R R 4 3 24 5 12 15 16 14 D&S E RR B LK L 9 3 11 6 2 9 10 1 17 D&SE RR B LK M21 B LK M21 11 13 8 7 18 1 0 7 2 4 5 8 2 1 D&SE RR BLK B 3 C UMMINGS 1 2 1 3 1 6 20 7 4 3 1 19 132 1 20 5 1 22 123 121 I & G N RR B LK 4 M2 M21 Z L V V B4 B3 V B4 B4 23 4 Cockrell Ranch W.O. Operating Lease Map & 2008 Acquisition Targets FEET 0 2, 000 4,00 0 6, 000 REMAR KS For: Pat McK inney By : Kim ble PETRA 1 1 /2 7 /2 0 07 2: 0 :07 PM Over 4,000 Acres identified in Brown Dolomite formation •Initiated Discussions with 3 Operators •Preliminary Economics: Waterflood PUD Reserves: 7.3 MMBOE $70/$7.50 NPV-10:$125MM $60/ $7 NPV-10:$100MM $45/$5 NPV-10:$50MM Plus ~5 MMBOE Probs/Poss

20 Cato Field Acquisition Cato Field Acquisition New Mexico New Mexico Cato Unit Cato Unit 15,300 acres 15,300 acres 220 wells acquired 220 wells acquired San Andres Dolomite: San Andres Dolomite: Porosity: 5 Porosity: 5-7% 7% Permeability: 20 md Permeability: 20 md Depth: 3,200 Depth: 3,200’ 60 wells currently producing 60 wells currently producing 100 boepd 100 boepd +100 additional wells to re +100 additional wells to re- activate and add pay activate and add pay Three pilot waterfloods in Three pilot waterfloods in field field Drilled on 40 acres spacing. Drilled on 40 acres spacing. 20 acre infill potential 20 acre infill potential CO CO-2 Line 4 miles away 2 Line 4 miles away TomTom / Tomahawk TomTom / Tomahawk 3,000 acres 3,000 acres 65 Wells 65 Wells Re Re-activation program: 20 activation program: 20 wells to re wells to re-activate, activate, swabbing, connecting swabbing, connecting powerline powerline Levelland Trend Cato San Andres Unit Cato Tomahawk TomTom NM TX

21 Three Prior Waterflood Pilots Three Prior Waterflood Pilots Amoco Pilot (1975) 11% OOIP Response 4 MMBWI Shell Pilot (1976) 5% OOIP Response 2.5 MMBWI Kelt Pilot (1990) Limited Response <1 MMBWI

Cato Field Reserves Cato Field Reserves Cato Field Secondary and Tertiary Recovery Profile Net MBOE Incr. % OOIP CUM OOIP% 0.3% 15.4% 0.7% 16.1% 9.48% 25.6% Gross $ $ Reserve Category CAPX $M $/BOE PDP PDNP PUD-WF 224 624 8,214 3,060 $ 4.90 47,850 $ 5.83 PROB-WF* 10,752 12.41% 38.0% * $ 40,650 $ 3.78 POSS-WF P0SS-CO2 2,317 8,067 2.67% 9.31% 40.7% 50.0% $ 66,050 $ 8.19 Total 30,198 50.0% $ 157,610 $ 5.22 *Texas A&M SPE Paper 27660- Study of 22 San Andres Waterflood projects in the Permian Basin yielded a mean recovery of 38% of OOIP

Cato Drilling • Cato FY 2008 Work Plan – RTP’ 31 wells – 10 wells WO electricity – Drilled Initial 20-acre infills P-1, P-2, P-3 and a new P-5 interval – Drilled 2 40- acre new wells with P-1 P-2 and P-3 Intervals – Will pick up third drilling rig on Jan 8rd

Cato Waterflood Development Cato 5 Cato 5-Year 20 Year 20-Acre Infill Program Acre Infill Program FY 2008 Acceleration Program: FY 2008 Acceleration Program: Secure three Drilling Rigs Secure three Drilling Rigs Drill 51 infill wells and initiate Drill 51 infill wells and initiate flood in prior Amoco Pilot area flood in prior Amoco Pilot area FY 2009: FY 2009: Drill 50 infill wells south of Amoco Drill 50 infill wells south of Amoco Pilot area and expand Pilot area and expand waterflood waterflood FY 2010: FY 2010: Drill 45 infill wells north of Shell Drill 45 infill wells north of Shell Pilot area and expand Pilot area and expand waterflood waterflood FY 2011: FY 2011: Drill 40 wells in Shell Pilot area Drill 40 wells in Shell Pilot area and expand and expand waterflood waterflood FY 2012: FY 2012: Drill 20 infill wells in Drill 20 infill wells in Kelt Kelt Pilot Pilot area and expand area and expand Waterflood Waterflood Total 20 Total 20-Acre Infill Wells~ 200 Acre Infill Wells~ 200

25 Desdemona Waterflood Desdemona Waterflood •~ 7,000 net Waterflood acres in the Duke Sand •Probable/Possible Waterflood/ASP reserves ~27 MMBOE 640 Acre Phase I Area

Desdemona Waterflood Response Central Battery 03 03 02 52 51 51 15 15 51 51 51 51 51 51 51 01 5 0 0 0 0 0 0 0 01 01 10 01 01 01 01 01 01 10 51 25 52 25 5 2 2 5 20 02 20 02 20 2 0 5 5 5 5 5 5 5 5 5 A -647 A-631 A -439 A-587 A-1903 A-378 A-1936 13 H HENDERSON R G E MOORE L A-543 A-969 M MC KINNEY S R ROBINSON Erath Co. 30-1 1 1 13 14 30-03 30-04 30-02 18-03 22-02 3 19-01 30-11 1 3 1 22-01 31-03 2 18-04 22-04 11-02 7 8 1 10 11 13 2 3 1 2 3 D-103 D-102 32-01 31-06 2 32-02 1 31-04 31-01 31-02 D-101 31-09 31-08 31-07 31-10 31-11 13-03 16-02 31-12 12-02 31-14 31-15 6 9 10 5 1 5 6 7 1 Square One Energy Hogtown-Moore Unit Duke Sand Net Oil Isopach Contour Interval: 5 ft. FEET 0 500 1,000 1,500 ATTRIBUTE MAP Zone: BIG_SA LIN E_S AND - BIG_SALINE_PRODUC ER IS PR ESENT Zone: BIG_SA LIN E_S AND - PR OPOSED_INJ_WELL [AJK] IS PR ESENT REMARKS For: Pat McKinney By: Kimble PE TR A 11 /2 8/ 2007 8 :1 9:5 5 AM Wells 30-11 and 30-15: 20% Oil-Cut

Nowata Nowata RTP RTP’s and ASP Pilot and ASP Pilot ASP Pilot Area Layout of softening + ASP injection equipment Pilot Plant is on site Pilot Plant is on site and final testing is and final testing is complete complete Full start Full start-up occurred in Dec up occurred in Dec- 2007 2007 Expect ASP response Expect ASP response in March/April 2008 in March/April 2008 ~5 MMBOE Possible Reserves ~5 MMBOE Possible Reserves

Nowata ASP Injection Plant ASP Injection Pumps ASP Control Panel ASP Breaker Room Polymer Hydration Tanks

University of Texas Research Grant University of Texas Research Grant • Initiated in Jan, 2007 with the Center for Petroleum and Geosystems Engineering Specific ASP research on four Cano Fields; Davenport, Desdemona, Nowata and Panhandle – Nowata Field: Current Status: Sandstone -Mature Waterflood existing ASP Challenge: Buttress current ASP recipe with a follow-on recovery mechanism Solution: Developed a cyclic SP alternating CO-2 fourth stage recovery recipe – Davenport Field: Current Status: Sandstone - Mature Waterflood Challenge: Need high TDS solution Solution: Tested over 160 different ASP combinations to determine three optimal recipe's – Desdemona Field Status: Sandstone - Pending Waterflood Challenge: Develop Tertiary Recovery Mechanism Solution: Currently testing fluid-to-fluid properties; Encouraging ASP results to date – Panhandle Field Status: Dolomite - Pending Waterflood Challenge: Need Tertiary Recovery Mechanism; No CO-2 availability Solution: Develop ASP Tertiary recovery recipe for carbonates; Initial Testing Phase

FY 2008 Capital FY 2008 Capital Total: $78.00MM Total: $78.00MM * Includes $10 MM Barnett Shale Capital Program Deferral * * Increased Capital Spending from $57 MM to $78 MM Capital Detail 49% 22% 15% 14% New Well Drills ($38.3MM) Facilities ($17.5MM) Workovers / Conversions ($11.4MM) Other / Contingency ($10.8MM) Capital by Field 1% 3% 16% 1% 4% 35% 40% Panhandle ($31.3MM) Corsicana ($0.7MM) Desdemona ($2.3MM) Desdemona Marble Falls / Barnett ($12.3MM) Davenport ($0.9MM) Nowata ($3.4MM) Cato ($27.1MM)

2007 2007-2012 Act/Projected Capital 2012 Act/Projected Capital Capital Profile CAPX $ $90,000 $80,000 $70,000 $60,000 $50,000 $40,000 $30,000 $20,000 $10,000 FY 2007 Act FY 2008 FY 2009 FY 2010 FY 2011 FY 2012 $52,850 $78,000 $64,225 $62,625 $61,875 $66,000 Fiscal Year(1) CAPITAL SPENDING (NET M $) - FISCAL YEAR CATO CORSICANA DAVENPORT DESD+WF DESD Barnett NOWATA PANHANDLE PANTWIST TOTAL FY 2007 Act $9,600 $1,912 $2,138 $4,900 $12,100 $4,009 $18,191 $100 $52,850 FY 2008  $27,111 $694 $911 $2,331 $12,275 $3,421 $31,257 $0 $78,000 FY 2009 $24,000 $0 $0 $12,300 $1,150 $3,150 $23,625 $0 $64,225 FY 2010 $24,000 $0 $0 $12,100 $1,850 $1,050 $23,625 $0 $62,625 FY 2011 $24,000 $0 $0 $12,000 $2,000 $0 $23,875 $2,500 $61,875 FY 2012 $24,000 $0 $4,000 $12,000 $2,000 $0 $24,000 $5,000 $66,000 TOTAL $132,711 $2,606 $7,049 $55,631 $31,375 $11,630 $144,573 $7,600 $385,575

Production Profile Production Profile •Probable reserves risked at 50% of recovery volumes • Possible reserves risked at 75% of recovery volumes ** Compounded Annual Growth Rate (CAGR) +50% CAGR BOEPD

Income Model Income Model At $70.00/Bbl and $7.00/MCF  Fiscal year

Corporate Strategy Corporate Strategy - Execution Execution • Increase production/cash flow – Develop Panhandle Waterflood PUD’s • Water Injection commenced July, 2007 • Initial production response anticipated in 1Q/2Q-2008 – Convert Probable Reserves to Proved • Waterflood Response at Desdemona (1Q-2008) • Launch of Nowata SP project (Response Mar/Apr-2008) • Cato Field RTP’s, infills (Ongoing) and Waterflood (2008) • Apply SP at Davenport and Desdemona (2008-2009)

© Cano Cano Petroleum Inc., 2008