Quintana Capital Group, L.P. 3 RD QUARTER MEETING 2011 The Petroleum - - PowerPoint PPT Presentation

Quintana Capital Group, L.P.

3RD QUARTER MEETING 2011

The Petroleum Club Monday, September 12th, 2011 8:30 a.m. to 5:00 p.m.

3RD QUARTER MEETI NG

The Petroleum Club Monday, September 12th, 2011 8:30 a.m. to 5:00 p.m.

Meeting Objectives

8:30 a.m. to 9:00 a.m.  Fund Level

• Alignment on Return and Timing Objectives (Fund I/II)

 Investment Level:

• Alignment on Valuation and Exit Objectives for Key Investments
• Identify Critical Path Issues and Milestones for Key Investments
• Revisit and Align on Plan to Track Performance Against Objectives

 Establish Fund III Objectives

Fund Level Performance and Strategic Assessment

9:00 a.m. to 10:00 a.m. Fund Performance  Return Analysis (as of 6/30/11)  Exit and Return Scenarios  Uncommitted Capital and Balance Sheet  Current Valuations vs. Exit Scenarios (Opportunity Cost Analysis)

• J. McDonald

10:00 a.m. to 11:00 a.m. Strategic Assessment  Investment Horizon  Peer/Vintage Analysis & LP Expectations  Long Term QEP Objectives (Fund III)

• L. Soetenga

Investment Level Valuation and Exit Assessment

11:00 a.m. to 1:00 p.m. Downstream and Coal Services  Talen’s (30 Min each)  Taggart  AmerCable 12:00 p.m. Working Lunch – to be served at 12:00 1:00 p.m. to 2:30 p.m. Oil and Gas Services  MWD Services  Quintana WellPro 2:30 pm to 4:00 pm Oil and Gas Upstream  Irion Minerals  Prize Petroleum  Deep Gulf Energy I/II

Board Meeting

4:00pm – 5:00 pm Board Meeting

Quintana Capital Group, L.P.

Financial Overview

September 12, 2011 9:00am to 10:00am Jimmy McDonald

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Quintana Capital Group, L.P.

• Status of Funds
• Fund I & II Scenarios
• Hurdle Review

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Quintana Capital Group, L.P.

Status of Funds

Fund I

• $0.00 Unallocated Dry Powder
• $40.0 million Allocated Dry Powder
• $46.6 million outstanding under the Citi facility

(including Kopper Glo Note Payable)

– $4.0 million available under the Citi facility

• Approximately $5.3 million of liquidity

available for portfolio company capital calls (capital needs in excess of current liquidity will require a Fund capital call)

Fund II

• $56.4 million Unallocated Dry Powder
• $155.0 million Allocated Dry Powder
• $58.4 million outstanding under the Natixis

facility (including Chase LC’s)

– $16.6 million available under the Natixis facility

• Approximately $18.3 million of liquidity

available for portfolio company capital calls (capital needs in excess of current liquidity will require a Fund capital call)

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Fund I & II Scenarios

Fund I Scenario Total Proceeds Capital Returned Pref Return Undistr Pref Profit Split Carried Interest ROI IRR GP LP GP LP LP LP LP GP Total Fund GP LP GP (Capital interest) Total Fund GP LP GP (Capital interest) Scenario I - 6-30-11 Hypothetical Liquidation (p. 5) $32.8 $597.7 $24.7 $509.7 $88.0 $67.7 $0.0 $0.0 1.2x 1.3x 1.2x 1.3x 4.9% 8.1% 4.7% 8.1% Scenario II – exit scenarios (no impairments) (p. 6) $42.7 $775.3 $24.7 $522.8 $252.5 $24.7 $0.0 $0.0 1.5x 1.7x 1.5x 1.7x 8.8% 22.0% 8.3% 11.6% Scenario III – exit scenarios (with impairments1) (p. 6) $65.2 $752.8 $24.7 $520.3 $226.9 $0.0 $5.6 $22.0 1.5x 2.6x 1.4x 1.7x 8.8% 20.1% 8.1% 11.6%

1Investment in EFH and Talen's are impaired in Scenario III.

Fund II Scenario Total Proceeds Capital Returned Pref Return Undistr Pref Profit Split Carried Interest ROI IRR GP LP GP LP LP LP LP GP Total Fund GP LP GP (Capital interest) Total Fund GP LP GP (Capital interest) Scenario I - 6-30-11 Hypothetical Liquidation (p. 7) $33.9 $164.9 $9.2 $105.2 $14.0 $0.0 $45.7 $14.9 1.7x 3.7x 1.6x 2.1x 35.9% 73.4% 29.7% 35.4% Scenario II – Chase development fee2 (p. 8) $67.9 $264.8 $9.2 $120.9 $28.6 $0.0 $115.2 $36.0 2.6x 7.4x 2.2x 3.5x 34.7% 64.9% 29.4% 36.9% Scenario III – Chase = cost (p. 9) $51.1 $221.0 $9.2 $120.9 $28.6 $0.0 $71.4 $25.0 2.1x 5.6x 1.8x 2.8x 26.3% 52.2% 21.9% 29.6% Scenario IV – Chase = 50% cost (p. 10) $45.3 $206.0 $9.2 $120.9 $28.6 $0.0 $56.4 $21.3 1.9x 4.9x 1.7x 2.6x 23.1% 47.1% 19.1% 26.9% Scenario V – Chase = 0 (p. 11) $39.6 $191.0 $9.2 $120.9 $28.8 $0.0 $41.3 $17.5 1.8x 4.3x 1.6x 2.4x 20.0% 42.2% 16.3% 24.3%

2Chase development fee scenario assumes $75 million development fee plus expenses received by Chase Power Development LLC.

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Quintana Capital Group, L.P.

Fund I & II Scenarios - Assumptions

• Fund I 6-30-11 Hypothetical Liquidation (FAS Values reduced by outstanding fund debt)

EXIT ASSUMPTIONS Exit Date / Distribution Date Enterprise Value Net Debt 8/8 Equity Value QEP share net of promote per 6/30/11 FAS QEP Proceeds Net of Fund Debt Previously Distributed Capital / Realized Investments Total Distributions XL Prospect 12/31/2009

• Beryl Oil & Gas Company GP

12/31/2009

• 315,821

315,821 Gulfstream Terminals & Marketing, LLC 5/25/2011

• 4,407,189

4,407,189 IRION Minerals (partial interest) 5/25/2011

• 7,477,564

7,477,564 Cypress Eaglewood 5/25/2011

• 7,415,625

7,415,625 Stone Mountain Resources, Ltd 6/30/2011 150,510,000 18,700,000 131,810,000 26,362,000 6,843,320

• 6,843,320

Quintana WellPro 6/30/2011 90,800,000 (9,000,000) 99,800,000 92,800,000 89,490,000 9,500,000 98,990,000 Q Consolidated Oil Well Services, LLC 6/30/2011 173,800,000 21,500,000 152,300,000 142,837,000 142,837,000

• 142,837,000

Taggart Global, LLC 6/30/2011 79,240,426 6,900,000 72,340,426 34,000,000 34,000,000 1,768,793 35,768,793 AmerCable Incorporated 6/30/2011 201,823,949 122,100,000 79,723,949 43,609,000 43,609,000 687,195 44,296,195 Q Directional Drilling Company, LLC 6/30/2011 118,861,724 27,100,000 91,761,724 72,400,000 69,090,000 7,581,650 76,671,650 MWD Services, LLC (includes NES) 6/30/2011 35,000,000 (1,000,000) 36,000,000 26,600,000 25,080,070 173,298 25,253,368 Deep Gulf Energy, L.P. 6/30/2011 277,911,019 (33,200,000) 311,111,019 13,500,000 13,500,000 3,003,290 16,503,290 Kopper Glo Fuel Inc. 6/30/2011 70,926,316 10,400,000 60,526,316 48,325,000 48,325,000

• 48,325,000

Deep Gulf Energy II, L.P. 6/30/2011 211,055,726 (14,200,000) 225,255,726 9,980,000 6,049,375

• 6,049,375

Prize Petroleum, LLC 6/30/2011 160,757,211 48,400,000 112,357,211 58,819,000 56,486,437

• 56,486,437

Texas Energy Future LP 6/30/2011 35,000,000,000 34,000,000,000 1,000,000,000 4,180,000 4,180,000

• 4,180,000

IDS 6/30/2011 3,000,000

• 3,000,000

2,625,000 2,625,000

• 2,625,000

Talen's Marine & Fuel, LLC 6/30/2011 41,000,000 12,800,000 28,200,000 28,200,000 28,200,000

• 28,200,000

Team CO2, LLC 6/30/2011 8,122,511 (600,000) 8,722,511 4,363,000 3,535,500 154,166 3,689,666 IRION Minerals, LLC (remaining interest) 6/30/2011 5,060,000 (1,600,000) 6,660,000 6,660,000 6,660,000

• 6,660,000

Falcon VPP, LP 6/30/2011 209,570,000 198,300,000 11,270,000 11,270,000 2,043,015 5,488,359 7,531,374 Total QEP I 36,837,438,882 34,406,600,000 2,430,838,882 626,530,000 582,553,717 47,972,950 630,526,667

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Quintana Capital Group, L.P.

Fund I & II Scenarios - Assumptions

• Fund I Exit Assumptions (Scenario II & III)

EXIT ASSUMPTIONS Exit Date / Distribution Date Enterprise Value Net Debt 8/8 Equity Value QEP share net of promote QEP Proceeds Net of Fund Debt Previously Distributed Capital / Realized Investments Total Distributions XL Prospect 12/31/2009

• Beryl Oil & Gas Company GP

12/31/2009

• 315,821

315,821 Gulfstream Terminals & Marketing, LLC 5/25/2011

• 4,407,189

4,407,189 IRION Minerals (partial interest) 5/25/2011

• 7,477,564

7,477,564 Cypress Eaglewood 5/25/2011

• 7,415,625

7,415,625 Kopper Glo Fuel Inc. 10/15/2011 70,000,000 10,000,000 60,000,000 48,640,000 48,640,000

• 48,640,000

IDS 11/11/2011 3,500,000 1,250,000 2,250,000 3,218,750 * 3,218,750

• 3,218,750

Q Consolidated Oil Well Services, LLC 12/31/2011 175,000,000 28,000,000 147,000,000 134,217,000 134,217,000

• 134,217,000

Q Directional Drilling Company, LLC 12/31/2011 120,000,000 28,000,000 92,000,000 69,471,000 66,161,000 7,581,650 73,742,650 Taggart Global, LLC 8/15/2012 100,000,000 10,000,000 90,000,000 42,300,000 42,300,000 1,768,793 44,068,793 AmerCable Incorporated 8/15/2012 250,000,000 120,000,000 130,000,000 71,110,000 71,110,000 687,195 71,797,195 Team CO2, LLC 9/30/2012 6,000,000

• 6,000,000

3,001,200 2,173,700 154,166 2,327,866 Quintana WellPro 12/31/2012 120,000,000 (5,000,000) 125,000,000 114,449,000 111,139,000 9,500,000 120,639,000 Talen's Marine & Fuel, LLC 12/31/2012 25,800,000

• 25,800,000

25,800,000 25,800,000

• 25,800,000

IRION Minerals, LLC (remaining interest) 12/31/2012 10,000,000

• 10,000,000

10,000,000 10,000,000

• 10,000,000

MWD Services, LLC 6/30/2013 25,000,000

• 25,000,000

19,050,000 19,050,000 173,298 19,223,298 Navigate Energy Services 6/30/2013 30,000,000

• 30,000,000

16,459,200 14,939,270

• 14,939,270

Stone Mountain Resources, Ltd 12/31/2013 375,000,000

• 375,000,000

75,000,000 55,481,620

• 55,481,620

Deep Gulf Energy, L.P. 12/31/2013 622,222,038

• 622,222,038

30,000,000 30,000,000 3,003,290 33,003,290 Prize Petroleum, LLC 12/31/2013 199,347,590

• 199,347,590

110,000,000 107,667,437

• 107,667,437

Deep Gulf Energy II, L.P. 12/31/2015 406,272,853

• 406,272,853

20,000,000 16,069,375

• 16,069,375

Texas Energy Future LP 12/31/2015 35,000,000,000 34,000,000,000 1,000,000,000 3,000,000 3,000,000

• 3,000,000

Falcon VPP, LP Staggered 18,255,933

• 18,255,933

18,255,933 9,028,949 5,488,359 14,517,308 Total QEP I 37,556,398,414 34,192,250,000 3,364,148,414 813,972,083 769,996,101 47,972,950 817,969,051 *includes $1.25 million of notes receivable from IDS.

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Quintana Capital Group, L.P.

Fund I & II Scenarios - Assumptions

• Fund II 6-30-11 Hypothetical Liquidation (FAS Values reduced by outstanding fund debt)

EXIT ASSUMPTIONS Exit Date / Distribution Date Enterprise Value Net Debt 8/8 Equity Value QEP share net

• f promote per

6/30/11 FAS QEP Proceeds Net of Fund Debt Previously Distributed Capital / Realized Investments Total Distributions Mustang Creek Holdings LP 11/24/2010

• 9,850,000

9,850,000 Genesis Energy LP 11/24/2010

• 2,200,433

2,200,433 Chase Power Development LLC 6/30/2011 45,800,000 (900,000) 46,700,000 40,336,861 31,800,865

• 31,800,865

East Texas Oil & Gas LLC 6/30/2011 37,000,000 (3,500,000) 40,500,000 39,027,000 26,184,791

• 26,184,791

Quality Magnetite LLC 6/30/2011 22,500,000 1,800,000 20,700,000 17,591,000 17,591,000 5,530,073 23,121,073 Genesis Energy LP 6/30/2011 2,395,200,000 650,600,000 1,744,600,000 118,800,000 104,887,666

• 104,887,666

Q Argentina E&P Holdings 6/30/2011 1,100,000 (1,100,000) 2,200,000 2,078,975 809,060

• 809,060

CIM 6/30/2011 10,600,000 (3,400,000) 14,000,000 8,260,173

• Quintana Shipping

6/30/2011 53,000,000 24,000,000 29,000,000 2,173,395

• Total QEP II

2,565,200,000 667,500,000 1,897,700,000 228,267,404 181,273,382 17,580,506 198,853,888

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Quintana Capital Group, L.P.

Fund I & II Scenarios - Assumptions

• Fund II Exit Assumptions (Scenario II)

Scenario : Chase development fee

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EXIT ASSUMPTIONS Exit Date / Distribution Date Enterprise Value Net Debt 8/8 Equity Value QEP share net of promote QEP Proceeds Net of Fund Debt Previously Distributed Capital / Realized Investments Total Distributions Mustang Creek Holdings LP 11/24/2010

• 9,850,000

9,850,000 Genesis Energy LP 11/24/2010

• 2,200,433

2,200,433 Genesis Energy LP (partial interest) 7/22/2011

• 29,810,793

29,810,793 Genesis Energy LP (remaining interest) Staggered (a)

• 101,163,591

87,729,858

• 87,729,858

Q Argentina E&P Holdings 12/31/2011

• 1,269,915
• Chase Power Development LLC

12/31/2012 117,500,000

• 117,500,000

102,107,500 91,937,188

• 91,937,188

Quality Magnetite LLC 5/15/2013 35,000,000

• 35,000,000

34,405,000 34,405,000 5,530,073 39,935,073 East Texas Oil & Gas LLC 12/31/2013 75,033,817

• 75,033,817

72,257,566 58,337,768

• 58,337,768

CIM 12/31/2013 40,000,000 5,000,000 35,000,000 24,500,000 12,883,969

• 12,883,969

Quintana Shipping 12/31/2014 64,200,000 24,000,000 40,200,000 3,000,000

• Total QEP II

331,733,817 29,000,000 302,733,817 338,703,572 285,293,783 47,391,299 332,685,082

1Chase development fee scenario assumes $75 million development fee plus expenses received by Chase Power Development LLC.

(a) Remaining common units sold and distributed to LP's by 12/31/2012. 1st - 4th tranche waivers sold and distributed to LP's by 12/31/2012, 12/31/2013, 12/31/2014, 12/31/2015, respectively. Unit price assumed to be $23 for remaining common units and $25 for waiver units. Vesting of waiver units determined by $0 .0075 increase in distributions per quarter.

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Fund I & II Scenarios - Assumptions

• Fund II Exit Assumptions (Scenario III)

Scenario : Chase = cost EXIT ASSUMPTIONS Exit Date / Distribution Date Enterprise Value Net Debt 8/8 Equity Value QEP share net of promote QEP Proceeds Net of Fund Debt Previously Distributed Capital / Realized Investments Total Distributions Mustang Creek Holdings LP 11/24/2010

• 9,850,000

9,850,000 Genesis Energy LP 11/24/2010

• 2,200,433

2,200,433 Genesis Energy LP (partial interest) 7/22/2011

• 29,810,793

29,810,793 Genesis Energy LP (remaining interest) Staggered (a)

• 101,163,591

87,729,858

• 87,729,858

Q Argentina E&P Holdings 12/31/2011

• 1,269,915
• Chase Power Development LLC

12/31/2012 47,798,459

• 47,798,459

41,536,861 31,366,549

• 31,366,549

Quality Magnetite LLC 5/15/2013 35,000,000

• 35,000,000

34,405,000 34,405,000 5,530,073 39,935,073 East Texas Oil & Gas LLC 12/31/2013 75,033,817

• 75,033,817

72,257,566 58,337,768

• 58,337,768

CIM 12/31/2013 40,000,000 5,000,000 35,000,000 24,500,000 12,883,969

• 12,883,969

Quintana Shipping 12/31/2014 64,200,000 24,000,000 40,200,000 3,000,000

• Total QEP II

262,032,276 29,000,000 233,032,276 278,132,933 224,723,144 47,391,299 272,114,443 (a) Remaining common units sold and distributed to LP's by 12/31/2012. 1st - 4th tranche waivers sold and distributed to LP's by 12/31/2012, 12/31/2013, 12/31/2014, 12/31/2015, respectively. Unit price assumed to be $23 for remaining common units and $25 for waiver units. Vesting of waiver units determined by $0 .0075 increase in distributions per quarter.

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Fund I & II Scenarios - Assumptions

• Fund II Exit Assumptions (Scenario IV)

Scenario : Chase = 50% cost EXIT ASSUMPTIONS Exit Date / Distribution Date Enterprise Value Net Debt 8/8 Equity Value QEP share net of promote QEP Proceeds Net of Fund Debt Previously Distributed Capital / Realized Investments Total Distributions Mustang Creek Holdings LP 11/24/2010

• 9,850,000

9,850,000 Genesis Energy LP 11/24/2010

• 2,200,433

2,200,433 Genesis Energy LP (partial interest) 7/22/2011

• 29,810,793

29,810,793 Genesis Energy LP (remaining interest) Staggered (a)

• 101,163,591

87,729,858

• 87,729,858

Q Argentina E&P Holdings 12/31/2011

• 1,269,915
• Chase Power Development LLC

12/31/2012 23,899,230

• 23,899,230

20,768,430 10,598,118

• 10,598,118

Quality Magnetite LLC 5/15/2013 35,000,000

• 35,000,000

34,405,000 34,405,000 5,530,073 39,935,073 East Texas Oil & Gas LLC 12/31/2013 75,033,817

• 75,033,817

72,257,566 58,337,768

• 58,337,768

CIM 12/31/2013 40,000,000 5,000,000 35,000,000 24,500,000 12,883,969

• 12,883,969

Quintana Shipping 12/31/2014 64,200,000 24,000,000 40,200,000 3,000,000

• Total QEP II

238,133,047 29,000,000 209,133,047 257,364,502 203,954,713 47,391,299 251,346,012 (a) Remaining common units sold and distributed to LP's by 12/31/2012. 1st - 4th tranche waivers sold and distributed to LP's by 12/31/2012, 12/31/2013, 12/31/2014, 12/31/2015, respectively. Unit price assumed to be $23 for remaining common units and $25 for waiver units. Vesting of waiver units determined by $0 .0075 increase in distributions per quarter.

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Funds I & II Scenarios - Assumptions

• Fund II Exit Assumptions (Scenario V)

Scenario : Chase = 0 EXIT ASSUMPTIONS Exit Date / Distribution Date Enterprise Value Net Debt 8/8 Equity Value QEP share net of promote QEP Proceeds Net of Fund Debt Previously Distributed Capital / Realized Investments Total Distributions Mustang Creek Holdings LP 11/24/2010

• 9,850,000

9,850,000 Genesis Energy LP 11/24/2010

• 2,200,433

2,200,433 Genesis Energy LP (partial interest) 7/22/2011

• 29,810,793

29,810,793 Genesis Energy LP (remaining interest) Staggered (a)

• 101,163,591

87,729,858

• 87,729,858

Q Argentina E&P Holdings 12/31/2011

• 1,269,915
• Chase Power Development LLC

12/31/2012

• Quality Magnetite LLC

5/15/2013 35,000,000

• 35,000,000

34,405,000 34,405,000 5,530,073 39,935,073 East Texas Oil & Gas LLC 12/31/2013 75,033,817

• 75,033,817

72,257,566 48,167,456

• 48,167,456

CIM 12/31/2013 40,000,000 5,000,000 35,000,000 24,500,000 12,883,969

• 12,883,969

Quintana Shipping 12/31/2014 64,200,000 24,000,000 40,200,000 3,000,000

• Total QEP II

214,233,817 29,000,000 185,233,817 236,596,072 183,186,283 47,391,299 230,577,582 (a) Remaining common units sold and distributed to LP's by 12/31/2012. 1st - 4th tranche waivers sold and distributed to LP's by 12/31/2012, 12/31/2013, 12/31/2014, 12/31/2015, respectively. Unit price assumed to be $23 for remaining common units and $25 for waiver units. Vesting of waiver units determined by $0 .0075 increase in distributions per quarter.

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Hurdle Review

Quintana Capital Group, L.P.

Strategic Assessment

September 12, 2011 10:00 am – 11:00 am Loren Soetenga Confidential – Do Not Distribute

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Expected hold periods

• Commitment period ends September 15th

2011

• Investment period ends September 15th 2016
• Commitment period ends December 4th 2013
• Investment period ends December 4th 2018

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Fund Vintage Fund Size (Mn) First Reserve Fund XII 2008 8,821 USD First Reserve Fund XI 2006 7,800 USD Riverstone/Carlyle Global Energy and Power Fund IV 2008 6,000 USD EnCap Energy Capital Fund VII 2007 2,500 USD Quantum Energy Partners V 2008 2,500 USD Denham Commodity Partners Fund V 2008 2,022 USD EnCap Energy Capital Fund VI 2006 1,500 USD Lime Rock Partners V 2008 1,400 USD Quantum Energy Partners IV 2007 1,320 USD Quantum Resources 2006 1,200 USD Kayne Anderson Energy Fund IV 2006 950 USD Kayne Anderson Energy Fund V 2009 820 USD Quintana Capital I 2006 650 USD Lime Rock Resources 2006 450 USD Lime Rock Resources II 2009 410 USD Quintana Energy Partners II 2008 350 USD

Quintana Capital Group, L.P.

Number of PE Funds

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Fund Vintage

• Distr. (%)

DPI Called (%) Lime Rock Resources 2006 46% 102% EnCap Energy Capital Fund VI 2006 86% 88% First Reserve Fund XI 2006 33% 86% Quantum Resources 2006 6% 86% Quintana Capital I 2006 8% 83% Riverstone/Carlyle Global Energy and Power Fund IV 2008 20% 69% Lime Rock Partners V 2008 1% 64% EnCap Energy Capital Fund VII 2007 32% 63% Denham Commodity Partners Fund V 2008 31% 54% First Reserve Fund XII 2008 8% 52% Kayne Anderson Energy Fund IV 2006 0% 51% Quantum Energy Partners IV 2007 25% 39% Lime Rock Resources II 2009 0% 35% Quintana Energy Partners II 2008 6% 33% Quantum Energy Partners V 2008 13% 8% Kayne Anderson Energy Fund V 2009 0% 6%

Quintana Capital Group, L.P.

Capital ratios – report date 12/31/10 or later

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Fund Vintage

• Distr. (%)

DPI Called (%) Lime Rock Resources 2006 46% 102% EnCap Energy Capital Fund VI 2006 86% 88% First Reserve Fund XI 2006 33% 86% Quintana Capital I 2006 8% 83% Riverstone/Carlyle Global Energy and Power Fund IV 2008 20% 69% Lime Rock Partners V 2008 1% 64% EnCap Energy Capital Fund VII 2007 32% 63% Denham Commodity Partners Fund V 2008 31% 54% First Reserve Fund XII 2008 8% 52% Kayne Anderson Energy Fund IV 2006 0% 51% Lime Rock Resources II 2009 0% 35% Quintana Energy Partners II 2008 6% 33% Quantum Energy Partners V 2008 13% 8% Kayne Anderson Energy Fund V 2009 0% 6%

Quintana Capital Group, L.P.

Capital ratios – report date 3/31/11 or later

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Fund Vintage Quartile Net IRR (%) Multiple (X) Quintana Energy Partners II 2008 1 36% 1.74x EnCap Energy Capital Fund VI 2006 1 25% 1.63x Riverstone/Carlyle Global Energy and Power Fund IV 2008 1 21% 1.5x Lime Rock Resources 2006 1 9% 1.39x Lime Rock Partners V 2008 1 25% 1.38x EnCap Energy Capital Fund VII 2007 1 16% 1.25x Quintana Capital I 2006 2 5% 1.18x Denham Commodity Partners Fund V 2008 2 10% 1.17x First Reserve Fund XI 2006 2 3% 1.08x Lime Rock Resources II 2009 n/a n/m 1.08x Quantum Energy Partners IV 2007 3 % 1.x Kayne Anderson Energy Fund IV 2006 3 ‐6% .92x First Reserve Fund XII 2008 4 ‐18% .84x Quantum Resources 2006 4 ‐11% .82x Kayne Anderson Energy Fund V 2009 n/a n/m .64x Quantum Energy Partners V 2008 4 ‐33% .42x

Quintana Capital Group, L.P.

Performance Ratios - report date 12/30/10 or later

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Performance Ratios - report date 3/31/11 or later

Fund Vintage Quartile Net IRR (%) Multiple (X) Quintana Energy Partners II 2008 1 36% 1.74x EnCap Energy Capital Fund VI 2006 1 25% 1.63x Riverstone/Carlyle Global Energy and Power Fund IV 2008 1 21% 1.5x Lime Rock Resources 2006 1 9% 1.39x Lime Rock Partners V 2008 1 25% 1.38x EnCap Energy Capital Fund VII 2007 1 16% 1.25x Quintana Capital I 2006 2 5% 1.18x Denham Commodity Partners Fund V 2008 2 10% 1.17x First Reserve Fund XI 2006 2 3% 1.08x Lime Rock Resources II 2009 n/a n/m 1.08x Kayne Anderson Energy Fund IV 2006 3 ‐6% .92x First Reserve Fund XII 2008 4 ‐18% .84x Kayne Anderson Energy Fund V 2009 n/a n/m .64x Quantum Energy Partners V 2008 4 ‐33% .42x

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[BLANK]

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[BLANK]

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• Actions

– Return of capital $450-$550m (fund I & fund II) – Be firm on exit timeline

• Fund III

– Placement agents – Marketing timeline

Quintana Capital Group, L.P.

Long Term Objectives

Downstream and Coal Services

Talen’s Marine & Fuel Inc.

September 12, 2011 11:00 am – 1:00 pm George Dethlefsen

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Talen’s Marine & Fuel, Inc.

Review of Exit Assumptions

Equity Invested $47,115,387 Hold Period to Date (years) 3.5 Current FAS Equity Valuation (6/30/11) (100%) $28,200,000 Net Debt (Current) $10,700,000 Estimated FCF Yield 9.8% Projected Exit Enterprise Value $51,830,000 ROIC

(revised from exit assumptions information, which valued Talen's at less than FAS)

Projected Exit Equity Value $41,130,000 0.87x Projected Exit EV/TTM EBITDA Multiple 7.3x Exit Timing Dec‐12 (potential to be extended depending on O'Rourke Petroleum merger outcome) Implied IRR for Remaining Hold Period 28.5% Basis for Current Valuation Public Comparables EV/EBITDA Multiple 13.3x Transaction Comparables EV/EBITDA Multiple 7.3x (multiple Martin Midstream paid for L&L in Jan 2011) Exit Year EBITDA (less WC facility interest) $7,100,000 Historical and Projected Financials ($ 000's) 2008 2009 2010 2011E 2012E 2013E Revenue $343,600 $235,100 $299,400 $441,100 $449,900 $458,900 Gross Margin % 9.8% 13.7% 10.6% 9.2% 9.2% 9.2% EBITDA (less WC facility interest) $6,300 $6,200 $2,700 $7,000 $7,100 $7,300 EBITDA % 1.8% 2.6% 0.9% 1.6% 1.6% 1.6% Net Income $2,671 $2,051 ‐$3,063 $889 Interest Expense $2,987 $1,743 $2,410 $2,780 $2,500 $2,500 Debt Amortization (Paydown) $1,436 $808 $2,400 $2,400 $2,400 CapEx $11,600 $13,200 $7,900 $5,300 $5,400 $5,500 Free Cash Flow Estimate ‐$3,480 ‐$3,200 ‐$3,100 Last Valuation Date / Hold Period Assumption 6/30/2011 12/31/2012 Equity Value ‐$28,200,000 $41,130,000 Implied IRR 28.5%

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Talen’s Marine & Fuel, Inc.

Strategic Growth Initiatives

• Expand land-based lubricants business, potentially through a merger with O'Rourke Petroleum
• Expand services revenues and other non-fuel, non-lubricants businesses
• Rationalize pricing for high capital intensity businesses (midstreaming)
• Increase exposure to growing markets, such as unconvential gas plays
• Increase contract-based business with customers and attract new customers to full service docks

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Talen’s Marine & Fuel, Inc.

Key Milestones

Target Date

• 1. Restore positive free cash flow and reduce leverage by expanding higher margin

product lines and activities Jan-12

• 2. Increase return on capital employed by adjusting midstreaming pricing and

rationalizing assets Dec-11

• 3. Address incentives for non-management level employees

Dec-11

• 4. Review systems needs and upgrade where appropriate

Dec-11

• 5. Fully integrate UFL acquisition

Mar-12

• 6. Market window staying open - MLP acquirers having a currency

Jun-12

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Talen’s Marine & Fuel

Risks to the Exit Plan

• Management Alignment
• Management B Units are underwater and likely will not be at a level to provide incentives
• Selling to an MLP is the most attractive outcome -- this will bring uncertainty to management's career prospects
• Management has hinted at reluctance to giving up the reins in a combination with O'Rourke Petroleum
• Third Party Dependencies/Risks
• Stiff competition from larger players has depressed margins
• Management's ability to drive growth
• Higher diesel price environment has increased working capital requirements and strained the line of credit
• Environmental concerns always a risk when transporting diesel on the water
• Capital expenditure requirements can be unpredictable when dealing with such a large fixed asset base
• Fluctuations in diesel prices can cause gains/losses on inventory
• Market Fundamentals
• Deepwater drilling remains weak as the GoM recovers from the BP spill
• Recent refining capacity increases have placed an emphasis on distribution channels for the refiners
• Business activity in Louisiana remains depressed, as does traffic on the Intracoastal Waterway
• MLPs are benefiting from a low interest rate environment, which is expected to continue
• Oil companies are moving larger lubricants accounts to their own account
• Lubricant manufacturers are pushing to consolidate distribution channels and eliminate smaller players

Taggart USA Global, LLC

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Taggart Global USA, LLC

Review of Exit Assumptions

Equity Invested $47,500,000 Hold Period to Date (years) 4.5 Current FAS Equity Valuation (6/30/11) (100%) $80,000,000 Net Debt (Current) $10,000,000 Weighted Average Cost of Capital (6/30) 25.1% Projected Exit Enterprise Value $100,000,000 ROIC Projected Exit Equity Value $90,000,000 0.9x

(excludes distributions)

Exit Year TTM EBITDA $22,634,000 Projected Exit EV/TTM EBITDA Multiple 4.4x Exit Year Forward EBITDA $10,500,000 Projected Exit EV/Forward EBITDA Multiple 9.5x Exit Timing Aug‐12 Implied IRR for Remaining Hold Period 11.0% Basis for Current Valuation Public Comparables EV/EBITDA Multiple 8.0x Transaction Comparables EV/EBITDA Multiple 7.9x FAS Projections Historical and Projected Financials ($ 000's) 2007 2008 2009 2010 2011E 2012E 2013E Revenue $171,131 $244,699 $422,472 $369,661 $413,101 $350,000 $385,000 Gross Margin % 13% 15% 13% 9% 14% 11% 10% EBITDA ‐$5,650 $5,049 $15,861 $4,159 $22,634 $10,500 $11,600 EBITDA % ‐3.3% 2.1% 3.8% 1.1% 5.5% 3.0% 3.0% Net Income ‐$6,500 $2,662 $12,125 ‐$1,591 $14,415 ‐ ‐ CapEx $2,270 $1,721 $2,634 $1,583 $2,148 $1,300 $1,500 Backlog at 12/31 $145,438 $202,062 $188,833 $217,724 $234,000 Gross Profit Backlog at 12/31 $20,866 $27,392 $25,875 $28,869 $30,088 Prior Year Backlog GP as % of Actual GP 68% 58% 52% 75% 50% Last Valuation Date / Hold Period Assumption 6/30/2011 8/15/2012 Equity Value ‐$80,000,000 $90,000,000 Implied IRR 11.0%

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Taggart Global USA, LLC

Strategic Growth Initiatives

• Section 45s build out and operation - Estimated to contribute $120mm in EPC work and $5-10mm in

annual operating income

• Continued growth in South Africa - Expected to contribute $7mm in 2011 EBITDA and potential for

more in 2012

• Continued market penetration in Australia - Currently bidding on large projects
• Turnaround of North America EPC profitability - New controls put in place, results being judged

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Taggart Global USA, LLC

Key Milestones

Target Date

• 1. Cleaning up of related party transactions, minority interests, contingent liabilities,

litigation, and excess G&A Jan -12

• 2. Achieving >$20mm of EBITDA in 2011

Dec-11

• 3. Achieving profitability in North America

Dec-11

• 4. Restructuring operations contracts to ensure profitability

Dec-11

• 5. Growing backlog (specifically gross profit in backlog)

Mar-12

• 6. Market window staying open - Potential acquirers having a currency

Mar-12

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Taggart Global USA, LLC

Risks to the Exit Plan

• Management Alignment
• Management must buy in to cleaning up due diligence issues that arose in FLSmidth transaction
• Taggart management owns slightly more than 50% of the equity
• The Board, including management, has agreed to an exit plan that includes a 2012 auction process and sale
• Management is motivated and willing to sell
• Third Party Dependencies/Risks
• KPMG Audit
• Potential management changes
• Overall coal/commodity price environment
• Section 45 legislation / permitting
• Incorporation of Australia JV / Partnership with Ausenco
• Sale of Langfang business in China
• Litigation with Arcelor Mittal
• Market Fundamentals
• Robust demand for metallurgical coal worldwide
• Reduced demand for steam coal projects in North America - little room for growth from 2011 base in N.A.
• Strong demand for coal projects in China, Australia, Western Canada, and South Africa
• Seaborne-traded coal prices justify new infrastructure…for now
• Growth coming from international markets

AmerCable, Inc.

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AmerCable, Inc.

Review of Exit Assumptions

Equity Invested $52,386,000 Hold Period to Date (years) 4.1 Current FAS Equity Valuation (6/30/11) (54.6%) $43,609,000 Net Debt (Current) $124,292,000 Cost of Capital 19.2% Projected Exit Enterprise Value $250,000,000 ROIC Projected Exit Equity Value $125,708,000 1.3x Projected Exit EV/TTM EBITDA Multiple 8.7x Exit Timing Aug‐12 Implied IRR for Remaining Hold Period 49.5% Basis for Current Valuation Public Comparables EV/EBITDA Multiple 7.0x Transaction Comparables EV/EBITDA Multiple 8.7x Exit Year EBITDA ($ 000's) $31,700 Historical and Projected Financials ($ 000's) 2007 2008 2009 2010 2011E 2012E 2013E Revenue $202,797 $232,202 $155,331 $184,703 $253,700 $286,900 $256,800 Contribution Margin % 47.7% 44.9% 47.1% 45.2% 42.3% 43.9% 43.9% EBITDA $30,800 $31,700 $23,400 $21,000 $25,600 $31,700 $36,300 EBITDA % 15.2% 13.7% 15.1% 11.4% 10.1% 11.0% 14.1% Net Income ‐$5,500 $15,600 ‐$3,000 ‐$1,100 $4,800 $9,300 $12,500 CapEx $13,828 $6,807 $2,801 $3,022 $4,469 $3,419 $3,500 Taxes NA NA $700 NA $3,200 $6,200 $8,300 Last Valuation Date / Hold Period Assumption 6/30/2011 8/15/2012 Equity Value ‐$43,609,000 $68,636,568 Implied IRR 49.5%

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AmerCable, Inc.

Strategic Growth Initiatives

• Oil & Gas solutions - increasing sales to oil & gas drillers targeting shale plays
• Renewed focus on large offshore oil & gas projects (Chevron and Shell)
• MRO Business - increasing after-market sales to mining customers and partnering with new distributors
• n the oil & gas side
• International Mining - Panther brand rollout in China, Australia, and Latin America
• China Manufacturing Plant - Considering a scaled down version
• Alternative Energy - Expanding sales to non-First Solar customers and partnering with another

assemblies manufacturer

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AmerCable, Inc.

Key Milestones

Target Date

• 1. Demonstrate progress in turning around the oil & gas division

Dec-11

• 2. Succession planning - putting in place a SVP of Oil & Gas and a SVP of Mining

Dec-11

• 3. Achieving >$30mm of EBITDA in 2012 or having a credible plan to get there (if we

sell prior to Dec-12) Jun-12

• 4. Establishing a manufacturing presence in China (to provide a growth story to

potential buyers) Dec-11

• 5. Market window(s) staying open - Debt and equity capital markets

Jun-12

• 6. Winning large oil & gas projects (Chevron Jack St Malo, Bigfoot and Shell

Olympus) Dec-11

• 7. Increasing penetration in international markets (China, Australia in particular)

Dec-11

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AmerCable, Inc.

Risks to the Exit Plan

• Management Alignment
• Management must buy in to selling to a strategic acquirer for full value to be achieved
• Short term vs. Long term incentives must be reviewed and reconciled
• Most of management's options are out of the money below $270mm of EV
• The Board, including management, has agreed to an exit plan (timing)
• Third Party Dependencies/Risks
• Credit Agreement -- covenants are expected to be breached in 2H 2011; Refinancing is expensive
• Market window(s) staying open - Debt and equity capital markets
• Overall commodity price environment
• Margins -- raw material costs increasing, AmerCable has not had success in passing costs through to customers
• Competition from large, well capitalized organizations who are eyeing the energy/infrastructure space
• Regulatory environment in the Gulf of Mexico
• Market Fundamentals
• Robust demand for coal projects worldwide / Growth coming from international markets
• Solar installations continuing to climb
• Land drilling business in US extremely strong
• Offshore oil & gas projects moving forward globally, GoM still lagging
• Korean manufacturers putting pricing pressure on the cable market in oil & gas
• Shipyards making more purchasing decisions, focused on price

Oil and Gas Services

MWD Services & NES

September 12, 2011 1:00 pm – 2:30 pm Steve Thompson and Chris Baker

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MWD Services, LLC

6/30/2011 MWD & NES FAS Overview

Summary

Equity Invested $27,900,000 Hold Period to Date (years) 4 Current FAS Equity Valuation (6/30/11) (100%) $28,210,830 Cash (6/30/11) $1,011,905 Debt (6/30/11) $0 Ownership QEP 76.2% Mgmt 23.8%

Valuation Summary - MWD Services, LLC - 06.30.2011 Valuation Gross Net Equity QEP Equity Relative Applicable Valuation Method ($MM) Value Ownership Value Weighting Value Discounted Cash Flow - Multiple Method $23.2 78.3% $18.2 17.5% $3.2 Discounted Cash Flow - Perpetual Growth Method $13.9 78.3% $10.9 17.5% $1.9 Precedent Transaction Comparables - 6/30/11 LTM EBITDA $24.7 78.3% $19.3 35.0% $6.8 Public Trading Comparables - 6/30/11 LTM EBITDA $30.0 78.3% $23.5 15.0% $3.5 Public Trading Comparables - 2011E EBITDA $17.2 78.3% $13.4 15.0% $2.0 Implied Valuation Recommendation 100.0% $17.4 Investment in NES 13.8 $ 78.3% $10.8 100.0% $10.8 Total Value Recommendation $28.2

Basis for Current FAS Valuation Public Comparables EV/2011 EBITDA Multiple 6.4x Public Comparables EV/LTM EBITDA Multiple 8.0x Transaction Comparables EV/LTM EBITDA Multiple 6.6x WACC 15.0% 2011P EBITDA $2,671,767 FAS 157 Implied Enterprise Value Multiples LTM 7.3x 2011E 10.2x FAS 157 Implied Enterprise Value Multiples (Excl. NES) LTM 5.7x 2011E 7.9x

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MWD Services, LLC

• Continue to work to resolve MWD tool reliability issues and regain

lost customers

– MWDS lost 10 “Follow-me” rigs this year due to tool reliability issues (7 for Integrity, 3 for DDS, plus 1 job for Tri-City); Appendix I details drop in utilization. – Subsequently MWDS quarantined (“Q’d”) 7 boxes (14 strings) until they determined root cause. – Despite these issues, MWDS has recently picked up 7 jobs for Wolverine and Helmer and has additional work promised for 6 additional jobs once tools are available. – As of 9/7/11 all Q’d tools have been released back into the fleet. – Achieve stable utilization above 55% and correct MWDS market perception prior to marketing Company.

• NES achieving successful mwd runs in the lateral
• NES technology developments:

– Single board design – High temperature mwd – EM proto-type by 1/1/2012

• After the DDC transaction closes, potentially merge MWD with

NES creating a new directional platform

– Creates a directional platform with proprietary technology and scale providing NES with the tool run hours needed to prove commerciality of their mwd tool. – MWDS/NES/QEP to provide a business plan to enter the directional space by 10/31/2011

Milestones/Growth Initiatives Threats / Risks

• MWD tool reliability issues remain unresolved.
• NES’ mwd tool proved unreliable in commercial applications.
• Archer responds with a negative view on NES’ technology and

tools post their review and analysis.

• Macroeconomic weakness causing declining horizontal rig count.
• Material build out of incremental mwd capacity by major and

independent service providers delaying NES mwd commerciality and test runs.

• NES management incentive model currently has their c-units below

water requiring ~$42 million equity exit value for NES stand-alone in order for c-unit holders to be in the money.

• Achieving alignment with both management teams to approve

MWDS/NES merger.

Milestones/Growth and Threats

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MWD Services, LLC

Summary Financials & Projected Investment Returns

NES Equity Returns** MWD Summary Financials MWD Equity Returns*

2007 2008 2009 2010 2011E* 2012P Revenue $11.0 $13.4 $7.9 $14.1 $14.5 $15.58 EBITDA 3.3 $3.8 $0.9 $3.7 $3.3 $4.0 EBITDA % 30.1% 28.5% 11.7% 26.3% 22.5% 25.7% Monthly EBITDA / Kit** $16,346.2 $11,733.8 $2,854.5 $11,649.0 $9,740.8 $11,500.0 * Estimated based on Y.T.D. As of 6/30 plus annual average run rate ** Represents Y.T.D. through June

* Fleet of 29 kits. ** QEP makes $2mm investment in NES over next 12 months. NES achieved run-rate Revenue of $10.4 million in July 2011.

IRR (Benchmarked to 6/30/11 FAS)* Consolidated Equity Returns

* 6/30/2013 exit.

Case 1 $26.2 $29.4 $32.6 $35.8 $39.1 Case 2 $37.7 $42.2 $46.8 $51.4 $55.9 Case 3 $49.1 $55.1 $61.0 $66.9 $72.8 Case 4 $60.6 $67.9 $75.1 $82.4 $89.7 Case 5 $72.1 $80.7 $89.3 $97.9 $106.5 Case 1

• 3.1%

2.6% 8.1% 13.3% 18.3% Case 2 16.2% 23.0% 29.5% 35.6% 41.5% Case 3 32.7% 40.4% 47.7% 54.7% 61.4% Case 4 47.3% 55.9% 64.0% 71.7% 79.1% Case 5 60.7% 70.0% 78.8% 87.2% 95.2% Revenue NES 2013 Revenue Exit Multiple $8.0 $9.0 $10.0 $11.0 $12.0 2.0x $14.0 $16.0 $18.0 $20.0 $22.0 3.0x $22.0 $25.0 $28.0 $31.0 $34.0 4.0x $30.0 $34.0 $38.0 $42.0 $46.0 5.0x $38.0 $43.0 $48.0 $53.0 $58.0 6.0x $46.0 $52.0 $58.0 $64.0 $70.0 EBITDA Monthly EBITDA/Kit Exit Multiple $10,000.0 $11,000.0 $12,000.0 $13,000.0 $14,000.0 2.5x $12.2 $13.4 $14.6 $15.8 $17.1 3.5x $15.7 $17.2 $18.8 $20.4 $21.9 4.5x $19.1 $21.1 $23.0 $24.9 $26.8 5.5x $22.6 $24.9 $27.1 $29.4 $31.7 6.5x $26.1 $28.7 $31.3 $33.9 $36.5

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MWD Services, LLC

MWD / NES Combined Directional Business Model Case

Directional Business Model Rational

• Current MWDS projections and valuation support the NES investment to date, i.e. NES sunk cost of $14.5 million to date is potentially

97% covered off by MWDS’ projected valuation.

• Creating a combined directional platform provides the optionality to quickly recreate a sizeable independent directional player with

proprietary technology providing for:

– Creates a directional platform with proprietary technology and scale providing NES with the tool run hours needed to prove commerciality of their mwd tool. – Larger buyer universe for the combined companies as a standalone MWDS transaction will not hit the radar of most buyers and a full service directional platform could command a higher multiple.

• Estimated total capital to build a combined directional business with 62 kit capability is $ 30.0 million (based on DDC).
• Estimated 2013 EBITDA of $29.8 million to $44.6 million.

IRR (Benchmarked to 6/30/11 FAS)*

EBITDA Multiple Monthly EBITDA/Kit 59.8% $40,000.0 $45,000.0 $50,000.0 $55,000.0 $60,000.0 3.5x 29.6% 36.5% 43.0% 49.2% 55.0% 4.5x 44.8% 52.5% 59.8% 66.6% 73.1% 5.5x 58.2% 66.6% 74.5% 81.9% 89.0% 6.5x 70.3% 79.3% 87.8% 95.7% 103.3% 7.5x 81.3% 90.9% 99.9% 108.4% 116.4%

* 12/31/2013 exit.

Equity Returns

EBITDA Multiple Monthly EBITDA/Kit 20460.0% $40,000.0 $45,000.0 $50,000.0 $55,000.0 $60,000.0 3.5x $104.2 $117.2 $130.2 $143.2 $156.2 4.5x $133.9 $150.7 $167.4 $184.1 $200.9 5.5x $163.7 $184.1 $204.6 $225.1 $245.5 6.5x $193.4 $217.6 $241.8 $266.0 $290.2 7.5x $223.2 $251.1 $279.0 $306.9 $334.8

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MWD Services, LLC

APPENDIX

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MWD Services, LLC

MWD Utilization

• MWD’s currently has 29 tools and utilization remains above 2009 levels (when the Company averaged 26 tools for the year)

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MWD Services, LLC

Comparable Transactions

NES Comparable Transactions

Date Acquiror Target

TEV/ TTM Revenue

6/24/2008 Schlumberger Extreme Engineering 8.0x 2/2/2008 Flotek Teledrift 5.7x 9/15/2007 GE Sondex 4.5x 6/30/2004 Sondex Geolink 2.6x Mean 5.2x Median 5.1x

• Comparable downhole tool transactions have commanded robust 3.0x – 8.0x TTM revenue multiples.

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MWD Services, LLC

DDC Monthly EDITDA / Kit

Historical DDC EBITDA / Kit

2008 2009 2010 2011E 2012P EBITDA ($MM) $18.6 $4.4 $12.4 $25.1 $34.0 Kit 28 26 32 44 52 Monthly EBITDA / KIT $55,357 $14,103 $32,292 $47,538 $54,487 Average('08,'10-'12) $47,418

Quintana WellPro S.A.

Investment Level Valuation & Exit Assessment

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Quintana WellPro S.A.

• Management Overview / Concerns:

– B-unit alignment – Based on IRR threshold rather than ROI, B- unit contribution relative to Tom’s A-units is minimal – Broad process vs. focused process vs. merger  IPO; Tom has material concerns regarding a broad marketing effort – Tom’s base salary, expense acct, etc. are sufficient to allow him to “time” the exit to maximize returns – Succession planning ($5million key man insurance) – Ensure exit incentives are aligned via a transaction bonus (to be shared amongst all senior management)

• Political instability in Las Heras has halted all activity and driving

utilization lower, 3 rigs idled and 4 others disrupted by instability – Many operators are waiting on 2011 election results and union solutions to contract rigs

• DLS, ODE, and H&P are main competition in the high HP drilling

rig market. Rumor is that Archer is moving GWES pressure pumping and completion assets to Argentina, potential for Saxon, and other NA drilling firms to chase Argentine shale market

• Tom recently stated that San Antonio (All rigs<1,250 HP) has

embraced a strategy “bidding utilization at all costs”

• Key Energy recently fired their operations manager and replaced

him with a lower level manager to manage workover business (potential positive)

Exit Risks and Threats Exit Discussion

• Consistent with previous discussions, QEP plans to exit QWP via a

sale or merger in 2012 once: – Rig #20 is constructed and contracted, – Rigs 18 and 19 are re-contracted, and – Overall contracted fleet utilization reaches 65-80%, and/or absent longer term contracts the track record for short term work demonstrates acceptable rig utilization capacity.

Exit Assumptions & Threats

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Quintana WellPro S.A.

6/30/2011 FAS Overview

Summary

* Includes cash held at IPE. Valuation Summary Equity Relative Applicable Valuation Method ($m) Value Weighting Value Discounted Cash Flow (Average Value) $94.4 70.0% $66.1 Public Trading Comparables $119.8 10.0% $12.0 Precedent Transaction Comparables $108.5 20.0% $21.7 Implied Valuation - Consolidated 100% $99.8 Implied ROI - Consolidated 1.60x Management A-Unit Value $3.5 Management B-Unit Value $3.5 Net Value to QEP $92.8 Implied QEP ROI 1.54x

Equity Invested $62,441,731 Hold Period to Date (years) 5 Current FAS Equity Valuation (6/30/11) (100%) $99,767,925 Cash (6/30/11)* $18,343,449 Debt (6/30/11) $9,388,200 A‐Unit Ownership QEP 96.5% Tom Murphy 3.5% Basis for Current FAS Valuation Public Comparables EV/2011 EBITDA Multiple 4.8x Public Comparables EV/LTM EBITDA Multiple 8.1x Transaction Comparables EV/LTM EBITDA Multiple 4.9x WACC 22.4% 2011P EBITDA $17,092,000 FAS 157 Implied Enterprise Value Multiples LTM 4.4x 2011E 5.3x

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Quintana WellPro S.A.

Historical Results & Projections

Historical & Projected Income Statement

• 2012 and 2013 projections are based on long-term historical fleet utilization of ~65%, inclusive of $500,000 of TA EBITDA for all periods,

utilizing Tom’s latest update for day rates and EBITDA margin assumptions. – Note: historical financial results yielded much higher EBITDA margins and total nominal cash flow on a smaller rig fleet relative to current forward projections due to Tom’s view on the market and pricing pressure. – Utilizing historical day rates and EBITDA margin assumptions for drilling and workover rigs, QWP’s fleet has a total annual cash flow capacity of approximately $47 million.

(USD in thousands) 2008A 2009A 2010A 2011E 2012E 2013E

Total Revenue 64,336.6 55,379.9 78,308.2 73,595.8 79,369.5 80,735.7 Growth Rate (13.9%) 41.4% (6.0%) 7.8% 1.7% Direct Costs 37,750.3 32,403.9 49,519.8 57,717.0 51,380.9 51,240.5 EBITDA 26,586.3 22,976.0 28,788.4 15,878.8 20,131.2 21,522.1 % Margin 41.3% 41.5% 36.8% 21.6% 25.4% 26.7%

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Quintana WellPro S.A.

Projected Investment Returns

Implied Equity Value Implied IRR (Benchmarked to 6/30/11 FAS)

* Long-term historical fleet utilization of ~65%. 2012 Exit 2013 Exit 2012 Exit 2013 Exit Fleet Utilization Exit Multiple ‐20% ‐10% LT Average* + 10% + 20% 4.0x 73.7 $ 77.9 $ 104.0 $ 126.9 $ 128.2 $ 4.5x 79.7 84.6 114.1 139.6 141.5 5.0x 85.6 91.2 124.1 152.4 154.8 5.5x 91.5 97.9 134.2 165.2 168.1 6.0x 97.4 104.5 144.3 177.9 181.4 Fleet Utilization Exit Multiple ‐20% ‐10% LT Average* + 10% + 20% 4.0x 84.0 $ 89.1 $ 119.5 $ 147.9 $ 150.0 $ 4.5x 90.4 96.3 130.2 161.5 164.2 5.0x 96.8 103.5 141.0 175.1 178.4 5.5x 103.2 110.6 151.7 188.7 192.6 6.0x 109.6 117.8 162.5 202.2 206.8 Fleet Utilization Exit Multiple ‐20% ‐10% LT Average* + 10% + 20% 4.0x (18.2%) (15.1%) 2.8% 17.3% 18.1% 4.5x (13.9%) (10.4%) 9.3% 25.0% 26.1% 5.0x (9.7%) (5.8%) 15.6% 32.5% 33.9% 5.5x (5.6%) (1.3%) 21.7% 39.7% 41.4% 6.0x (1.6%) 3.1% 27.7% 46.8% 48.7% Fleet Utilization Exit Multiple ‐20% ‐10% LT Average* + 10% + 20% 4.0x (10.8%) (7.2%) 12.7% 29.9% 31.1% 4.5x (6.3%) (2.3%) 19.3% 37.7% 39.2% 5.0x (2.0%) 2.4% 25.8% 45.2% 47.1% 5.5x 2.3% 7.1% 32.1% 52.6% 54.7% 6.0x 6.4% 11.7% 38.2% 59.8% 62.2%

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Quintana WellPro S.A.

Projected Investment Returns – NAV

NAV

2012 Exit 2013 Exit

# of Rigs Value / Rig Total # of Rigs Value / Rig Total Drilling Rigs 9 $11.4 $102.6 Drilling Rigs 9 $11.4 $102.6 Workover Rig 9 $1.0 $9.0 Workover Rig 9 $1.0 $9.0 Pulling Rigs 2 $1.0 $2.0 Pulling Rigs 2 $1.0 $2.0 Rig value $113.6 Rig value $113.6 Working Capital (12/31/12) $25.0 Working Capital (12/31/13) $25.5 Top Drives 3 $1.5 $4.5 Top Drives 3 $1.5 $4.5 Net Debt (12/31/12)

• $23.5

Net Debt (12/31/13)

• $33.4

Equity Value $166.6 Equity Value Total $177.0 Discount To Bronco Valuation: Discount To Bronco Valuation: 10% $149.92 10% $159.28 15% $141.59 15% $150.43 20% $133.26 20% $141.58

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Projected Investment Returns – Maximum Cash Flow Potential* (100% Utilization)

Implied Equity Value

• The table below is based on QWP’s maximum cash flow capacity of $47 million based on historical day rates and EBITDA margins

at 100% utilization. Exit Year Exit Multiple 2012 2013 4.0x 224.4 $ 250.2 $ 4.5x 247.9 273.5 5.0x 271.5 296.8 5.5x 295.0 320.0 6.0x 318.5 343.3

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APPENDIX

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2011 Budgeted Utilization vs. Actual Utilization Y.T.D.

QUINTANA WELLPRO Current Contract Schedule & Expected Utilization (Expected Case) Date: 1/1/11 FY2011 Rig Base Type D HRS Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Total Rig 1 Neuquen Workover 7.0 D 24 Hrs

100% 100% 95% 95% 95% 95% 95% 95% 95% 95% 95% 95%

95.8% Rig 2 Neuquen Workover 7.0 D 24 Hrs

0% 0% 0% 0% 0% 95% 95% 95% 95% 95% 95% 95%

55.4% Rig 3 Neuquen Workover 7.0 D 24 Hrs

0% 0% 0% 0% 95% 95% 95% 95% 95% 95% 95% 95%

63.3% Rig 4 Comodoro Pulling 7.0 D 24 Hrs

100% 100% 95% 95% 95% 95% 95% 95% 95% 95% 95% 95%

95.8% Rig 5 Neuquen Pulling 7.0 D 24 Hrs

76% 80% 95% 95% 95% 95% 95% 95% 95% 95% 95% 95%

92.2% Rig 6 Neuquen Drilling 7.0 D 24 Hrs

0% 18% 0% 95% 95% 95% 95% 95% 95% 95% 95% 95%

72.7% Rig 7 Comodoro Workover 7.0 D 24 Hrs

0% 0% 0% 0% 50% 50% 50% 50% 50% 50% 50% 50%

33.3% Rig 8 Comodoro Workover 7.0 D 24 Hrs

0% 0% 0% 0% 0% 0% 0% 0% 0% 50% 50% 50%

12.5% Rig 9 Chile Drilling 7.0 D 24 Hrs

0% 12% 95% 95% 95% 95% 95% 95% 95% 95% 95% 95%

80.2% Rig 10 Comodoro Workover 7.0 D 24 Hrs

0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 50% 50%

8.3% Rig 11 Comodoro Workover 7.0 D 24 Hrs

0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 50%

4.2% Rig 12 Chile Drilling 7.0 D 24 Hrs

0% 0% 0% 0% 0% 0% 95% 95% 95% 95% 95% 95%

47.5% Rig 13 Neuquen Drilling 7.0 D 24 Hrs

100% 100% 95% 95% 95% 95% 95% 95% 95% 95% 95% 95%

95.8% Rig 14 Neuquen Workover 7.0 D 24 Hrs

0% 0% 0% 0% 0% 0% 0% 95% 95% 95% 95% 95%

39.6% Rig 15 Comodoro Workover 7.0 D 24 Hrs

100% 100% 95% 95% 95% 95% 95% 95% 95% 95% 95% 95%

95.8% Rig 16 Chile Drilling 7.0 D 24 Hrs

0% 0% 0% 0% 95% 95% 95% 95% 95% 95% 95% 95%

63.3% Rig 17 Neuquen Drilling 7.0 D 24 Hrs

0% 0% 0% 0% 0% 0% 0% 0% 0% 95% 95% 95%

23.8% Rig 18 Neuquen Drilling 7.0 D 24 Hrs

100% 100% 95% 95% 95% 95% 95% 95% 95% 95% 95% 95%

95.8% Rig 19 Neuquen Drilling 7.0 D 24 Hrs

100% 100% 95% 95% 95% 95% 95% 95% 95% 95% 95% 95%

95.8% Rig 20 Neuquen Drilling 7.0 D 24 Hrs

0% 0% 0% 0% 0% 0% 0% 95% 95% 95% 95% 95%

39.6% Average: 33.8% 35.5% 38.0% 42.8% 54.8% 59.5% 64.3% 73.8% 73.8% 81.0% 83.5% 86.0% 60.5% QUINTANA WELLPRO Updated Contract Schedule & Expected Utilization Date: 7/31/11 FY2011 Rig Base Type D HRS Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Total Rig 1 Neuquen Workover 7.0 D 24 Hrs 95% 100% 99% 98% 97% 99% 100% 98.2% Rig 2 Neuquen Workover 7.0 D 24 Hrs 0% 0% 0% 98% 100% 100% 100% 56.9% Rig 3 Neuquen Workover 5.0 D 24 Hrs 0% 0% 30% 100% 100% 100% 100% 61.5% Rig 4 Comodoro Pulling 7.0 D 24 Hrs 100% 100% 100% 100% 99% 98% 100% 99.6% Rig 5 Neuquen Pulling 7.0 D 24 Hrs 57% 67% 100% 99% 98% 98% 98% 88.2% Rig 6 Neuquen Drilling 7.0 D 24 Hrs 0% 18% 67% 100% 100% 100% 51% 62.3% Rig 7 Comodoro Workover 7.0 D 24 Hrs 0% 0% 0% 0% 0% 0% 0% 0.0% Rig 8 Comodoro Workover 7.0 D 24 Hrs 0% 0% 0% 0% 0% 0% 0% 0.0% Rig 9 Chile Drilling 7.0 D 24 Hrs 0% 12% 100% 100% 80% 0% 0% 41.8% Rig 10 Comodoro Workover 7.0 D 24 Hrs 0% 0% 0% 0% 0% 0% 0% 0.0% Rig 11 Comodoro Workover 7.0 D 24 Hrs 0% 0% 0% 0% 0% 0% 0% 0.0% Rig 12 Chile Drilling 7.0 D 24 Hrs 0% 0% 0% 0% 0% 0% 0% 0.0% Rig 13 Neuquen Drilling 7.0 D 24 Hrs 100% 100% 100% 98% 100% 80% 0% 82.5% Rig 14 Neuquen Workover 7.0 D 24 Hrs 0% 0% 0% 0% 0% 0% 0% 0.0% Rig 15 Comodoro Workover 7.0 D 24 Hrs 100% 99% 100% 100% 98% 100% 99% 99.5% Rig 16 Chile Drilling 7.0 D 24 Hrs 0% 0% 0% 92% 100% 100% 100% 56.0% Rig 17 Neuquen Drilling 7.0 D 24 Hrs 0% 0% 0% 0% 70% 93% 99% 37.3% Rig 18 Neuquen Drilling 7.0 D 24 Hrs 100% 97% 100% 100% 99% 13% 99% 86.9% Rig 19 Neuquen Drilling 7.0 D 24 Hrs 100% 90% 100% 100% 100% 99% 100% 98.4% Rig 20 Neuquen Drilling 7.0 D 24 Hrs 0% 0% 0% 0% 0% 0% 0% 0.0% Average: 34.3% 36.0% 47.2% 62.4% 65.2% 56.9% 55.1% 0.0% 0.0% 0.0% 0.0% 0.0% 48.5% Regimen Contract Counterparty Regimen Contract Counterparty

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Current Active Rigs and Contract Tenor

Rig Status Date: 09/04/11 Contracted / Counterparty Remaining Comments (Status of contract, tender market for rig, expectations for default/repricing requests, etc) Standby / Contract Tendering Tenor Rig 1 Contracted Entre Lomas 1 Normal Operations. Rig 2 Contracted San Jorge 2 Preparing to mobilize for San Jorge. Rig 3 Contracted Medanito 2 Normal Operations. Rig 4 Contracted Sinopec 3 Operating with risk of social unrest. Rig 5 Contracted Entre Lomas 1 Normal Operations. Rig 6 Tendering Damaged mast after rig move. Under repair in Neuquen. Rig 7 Tendering Ready in Las Heras Yard. Marketing. Rig 8 Contracted Entre Lomas 2 Normal Operations. Rig 9 Tendering Ready in Punta Arenas Yard. Marketing. Rig 10 Contracted Crown Point 1 Force majeure for Crown Point due to social unrest. Rig 11 Tendering Ready in Las Heras Yard. Marketing. Rig 12 Tendering In Rio Grande yard. Marketing. Rig 13 Contracted Crown Point 1 Force majeure for Crown Point due to social unrest. Rig 14 Tendering Ready in Neuquen Yard. Marketing. Rig 15 Contracted Sinopec 3 Operating with risk of social unrest. Rig 16 Contracted Medanito 2 Normal Operations. Rig 17 Tendering Ready in Neuquen Yard. Marketing. Rig 18 Contracted San Jorge 1 Normal Operations. Rig 19 Contracted Apache 1 Drilling last well under well-to-well contract for Apache. Marketing. Rig 20 Construction On Hold Rigging up in Neuquén yard. Started SCR and raised mast. De-bugging SCR. Testing rig equipment. Preparing to install top drive. One engine has factory flaw. Dealer repairing under warranty

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• Partner with Tom Murphy to form a new company focused on meeting the drilling and workover needs of the Argentine and South

American O&G markets.

Original Investment Thesis Original Risks & Mitigants

• Political – current President Néstor Kirchner has a high approval rating although recent international trade conference underscores region’s

hostility toward the US; present relations with Chile (violated gas export agreement) and Bolivia (nervous that Argentina will import gas and re-sell to Chile) are strained; tax laws (i.e., see below point about export tax duties); union labor

• Regulatory – Ministry of Energy provides the broadest regulatory oversight with certain other agencies and associations created to monitor

specific sectors (e.g., El Ente Nacional Regulador de la Electridad (ENRE) and El Ente Nacional Regulador del Gas (ENARGAS); American Petroleum Institute services/equipment specifications; two year mast inspections, pollution control, night move restrictions and specific operating procedures are among regulatory requirements

• Business – level of capital spending (usually depends on current/expected commodity prices) by companies for exploration, development and

production activities affect the drilling service industry; rates depend on rig supply/demand, equipment condition, and service/safety record; equipment purchases might encounter time delays or cost fluctuations due to current strength in global oil and gas markets

• Competition – Pride, DLS, WellTech, and Nabors comprise the key competitors (each has scale); Murphy has had numerous interactions with

likely key customers and interest is strong; should the market slacken, QWP’s equipment (though additive to the overall Argentine fleet) will remain under contract longer as it is higher quality than mom-and-pops’ and other competitors’ equipment

• Exchange rate fluctuations – Argentina appears to have stabilized economically with inflation down from yesteryear peaks of 20%+, which

should foster more direct investment, stability in, and demand for the Argentine peso (already down from a high of 3.88 Pesos:$US1 to 2.97:1 today); payment for drilling services will be based on dollars so there will be a currency risk re: US$

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• QWP out-performed the initial financial projections in all periods driven by a strong demand for drilling/workover services during these time

periods and the ability to obtain long term contracts and high mobilization fees

• The QWP rig fleet has grown faster than expected (20 rigs currently vs. 17 projected) and includes larger HP rigs than projected
• Greater than expected tax leakage due to legal structure

– Largely the result of transferring the investment from a Robertson family holding to a QEP portfolio company.

• Difficulty in transferring funds from Argentina

Material Differences to Plan Original EBITDA & Rig Count Projections/Results

Year End Rig Count 2007 2008 2009 2010E 2011P Original Projections 11 13 15 17 17 Actual Results 13 17 19 19 20

$3.5 $8.0 $10.7 $12.5 $13.6 $13.8 $26.6 $23.0 $28.8 $15.9 5 10 15 20 25 30 35 2007 2008 2009 2010 2011E

Original Proj. Actuals

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QWP will follow a disciplined strategy toward creating value for its stakeholders:

• Create a talented team of senior and field-level personnel focused on low-cost, nimble operations
• Cost effectively build quality assets through remanufacturing stacked rigs and tuck-in acquisitions
• Provide first-in-class service at every level of the organization
• Pursue long-term relationships and drilling contracts with escalators from active E&P companies
• Opportunistically seek to provide supplemental oilfield services and to participate in E&P projects

Secondarily, QWP strategy includes the following principles:

• Maintain flexibility to respond to changing conditions
• Maintain a conservative and flexible balance sheet
• Continually improve safety, quality and efficiency
• Implement leading edge technology where cost-effective to do so

Original Business Strategy Original Growth Initiatives

• 2 pulling rigs, 3 workover rigs, and 1 drilling rig put into service starting in December 2006
• 4 workover rigs and 1 drilling rig put into service in mid-March 2007
• 1 workover rig and 1 drilling rig put into service in mid-March 2008
• 1 workover rig and 1 drilling rig put into service in mid-March 2009
• 1 workover rig and 1 drilling rig put into service in mid-March 2010

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2011 Budget

Actual Actual Actual Actual Budget Budget Budget Budget Budget Budget Budget Budget Budget Ene'11 Feb'11 Mar'11 Abr'11 May'11 Jun'11 Jul'11 Ago'11 Sep'11 Oct'11 Nov'11 Dic'11 FY2011 Revenues Well Service Revenue 1,423.3 1,514.0 1,590.7 2,007.5 1,904.7 2,344.4 2,553.5 2,716.9 2,503.0 2,709.3 2,644.6 2,678.5 26,590.3 Drilling Revenues 1,598.7 2,093.8 4,067.8 5,242.9 4,361.5 2,857.9 2,639.5 3,022.6 4,315.4 5,665.2 5,495.5 5,644.8 47,005.6 Mobilizat ion Revenues 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Ot her Revenues 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 TOTAL REVENUES 3,022.0 3,607.7 5,658.4 7,250.4 6,266.2 5,202.3 5,193.0 5,739.5 6,818.4 8,374.5 8,140.1 8,323.3 73,595.8 Direct Cost s Labor Cost s 1,961.1 2,256.5 2,418.0 3,449.4 2,836.2 2,119.4 2,188.7 2,765.2 3,202.7 3,275.8 3,677.2 3,605.8 33,756.0 Equipment Cost s 459.4 718.0 829.2 784.2 975.2 855.9 855.6 935.6 1,103.8 1,402.8 1,377.7 1,423.3 11,720.7 Ot her Cost s 179.3 155.3 361.8 227.3 548.9 648.9 559.3 561.8 595.4 727.1 709.4 728.3 6,002.9 TOTAL DIRECT COSTS 2,599.8 3,129.8 3,609.0 4,460.9 4,360.4 3,624.2 3,603.6 4,262.6 4,901.8 5,405.6 5,764.3 5,757.5 51,479.6 GROSS MARGIN 422.2 477.9 2,049.4 2,789.5 1,905.8 1,578.1 1,589.4 1,476.9 1,916.5 2,968.9 2,375.8 2,565.8 22,116.2 14.0% 13.2% 36.2% 38.5% 30.4% 30.3% 30.6% 25.7% 28.1% 35.5% 29.2% 30.8% 30.1% SG&A Salaries and Payroll Taxes 277.3 342.3 386.8 479.4 287.5 286.8 286.4 345.0 352.5 331.9 389.6 382.0 4,147.5 Ot her 197.0 173.0 271.6 215.3 211.9 213.6 214.6 215.9 216.6 218.3 220.1 222.1 2,589.9 Tot al G&A 474.2 515.3 658.4 694.7 499.4 500.4 501.0 560.9 569.1 550.2 609.8 604.1 6,737.4 EBITDA (52.0) (37.4) 1,391.0 2,094.8 1,406.4 1,077.7 1,088.4 916.0 1,347.5 2,418.7 1,766.0 1,961.7 15,378.8

• 1.7%
• 1.0%

24.6% 28.9% 22.4% 20.7% 21.0% 16.0% 19.8% 28.9% 21.7% 23.6% 20.9% DD&A 452.5 452.5 452.5 452.5 452.5 470.9 541.7 541.7 541.7 541.7 541.7 541.7 5,983.6 Ot her Income/ Expense 64.1 64.2 63.7 71.8 73.1 303.4 302.0 305.6 306.8 76.4 76.2 72.3 1,779.5 Income Tax (171.6) (208.6) 78.1 466.4 308.3 106.2 85.7 24.0 174.6 630.2 401.9 471.7 2,367.0 EBIT (397.0) (345.6) 796.6 1,104.0 572.5 197.2 159.1 44.7 324.3 1,170.4 746.3 876.0 5,248.6

• 13.1%
• 9.6%

14.1% 15.2% 9.1% 3.8% 3.1% 0.8% 4.8% 14.0% 9.2% 10.5% 7.1%

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Balance Sheet / Covenant Projections

Budget Budget Budget Budget 1Q11 2Q11 3Q11 4Q11 Assets Cash and Banks 20,765 15,784 12,997 11,221 Account Receivable 11,584 19,317 20,635 25,361 Inventory Parts & Supplies 11,739 11,717 10,937 10,037 VAT 171 Other Current Assets 5,404 6,555 7,198 7,198 Work in Progress (Capex) 8,311 3,981 7,696 8,781 Equipment & Other No Current Assets 43,599 50,543 48,918 49,493 Total Assets 101,573 107,896 108,381 112,091 Liabilities Accounts Payable (165) 3,404 3,643 4,197 Salaries/ Payroll Taxes Payable 2,291 2,406 3,555 3,988 Taxes Payables (1,717) 106 884 VAT 201 800 1,019 Accrued Expense 7,449 6,767 6,017 6,017 Loan Standard Bank 10,562 9,388 8,215 7,041 Other Liabilities 1,003 1,013 1,013 1,013 Total Liabilities 19,423 23,285 23,242 24,159 Stockholders Equity Common Stock 44,806 44,806 44,806 44,806 Retained Earnings 38,060 38,381 38,381 38,381 YTD Net Income (717) 1,424 1,952 4,745 Total Shareholders Equity 82,150 84,611 85,139 87,932 Total Liabilities and S/H Equity 101,573 107,896 108,381 112,091 Financial Covenants - Loan Debt 1Q11 2Q11 3Q11 4Q11 Senior Debt Coverage Ratio 0.56 0.75 1.03 0.91 Liabilities 12,138.78 13,114.39 13,582.26 13,945.10 Ebitda 21,862.46 17,384.93 13,143.12 15,378.78 Requirement < 2,50 2.50 2.50 2.50 2.50 Senior Debt Interest Coverage Ratio 23.15 17.41 11.75 14.34 Ebitda 21,862.46 17,384.93 13,143.12 15,378.78 Capex 8,688.99 8,505.81 7,975.00 9,760.00 Interest Expense 569.17 510.03 439.71 391.86 Requirement > 4,00 4.00 4.00 4.00 4.00 VTL Ratio 3.45 3.88 4.43 5.17 Value + Reserve 36,408.00 36,408.00 36,408.00 36,408.00 Amount of All Outstanding Loans 10,561.76 9,388.24 8,214.71 7,041.18 Requirement > 1,25 1.25 1.25 1.25 1.25 Tangible Net Worth Assets 101,573.08 107,896.48 108,381.32 112,090.99 Liabilities 19,423.47 23,285.50 23,242.25 24,159.21 Minimun Tangible Net Worth 22,000.00 22,000.00 22,000.00 22,000.00 Excess 60,149.61 62,610.98 63,139.07 65,931.79 Leverage Ratio 0.56 0.75 1.03 0.91 Requirement < 2,50 2.50 2.50 2.50 2.50

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Market Overview Historical Rig Count*

• Latin America is forecasted to be a growth market.

– Forecasted to grow at a CAGR of 12% from 2010 to 2012.

• Increasing Argentine oil prices are projected to drive continued

exploration in the country. – Oil prices are projected to increase at a CAGR of 4% from 2011 through 2026

• ExxonMobil, Total, Apache, NOCs, and others have all recently

announced initiatives to explore for unconventional oil and gas in Argentina

Rig Count Outlook – U.S. and Latin America*

Source: Smithbits Rig Count 1,892 1,881 1,942 2,068 1,990 1,257 932 1,035 1,195 1,409 1,588 1,736 1,801 1,760 376 373 403 430 448 432 425 431 435 442 441 447 460 471 96 90 90 90 81 65 51 56 60 71 79 87 85 83 500 1,000 1,500 2,000 2,500 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 U.S. Latin America Argentina

100 200 300 400 500 600 700 800 500 1,000 1,500 2,000 2,500

Q1 2006 Q2 2006 Q3 2006 Q4 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 2012

Latin American Rig Count U.S. Rig Count US Latin America

G&G Consulting Oil Price Forecasts

$20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120 $/Bbl Base Case Upside Case Downside Case Actual Source: Tudor Pickering & Holt Research Source: G&G Consulting

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Argentine Drilling Rig Market*

Fleet Contracted Market Share Contractor Size Rigs % Total % Contracted % San Antonio 42 33 79% 36% 38% DLS 21 18 86% 18% 21% H&P 9 4 44% 8% 5% Quintana WellPro 9 7 78% 8% 8% Nabors 8 4 50% 7% 5% YPF 7 2 29% 6% 2% Key 6 5 83% 5% 6% Ensign 5 5 100% 4% 6% Petreven 4 4 100% 3% 5% Venver 3 2 67% 3% 2% Sinopec 1 1 100% 1% 1% Estrella 1 1 100% 1% 1% Total 116 86 74% 100% 100% Fleet Contracted Market Share Contractor Size Rigs % Total % Contracted % San Antonio 113 98 87% 41% 45% DLS 45 43 96% 16% 20% Key 33 23 70% 12% 11% Venver 12 9 75% 4% 4% Emepa 11 9 82% 4% 4% Quintana WellPro 11 6 55% 4% 3% Nabors 10 7 70% 4% 3% YPF 8 4 50% 3% 2% Oil 6 3 50% 2% 1% Taker 5 5 100% 2% 2% Ensign 4 3 75% 1% 1% Estrella 3 3 100% 1% 1% Geopatagonia 3 0% 1% 0% Macrico 3 3 100% 1% 1% Petroneu 3 2 67% 1% 1% SPS 2 1 50% 1% 0% Other 6 0% 2% 0% Total 278 219 79% 100% 100%

Argentine Workover Rig Market*

*Data for reference purposes, note fleet size and contracted rig numbers as of April 2011 LP meeting

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Quintana WellPro S.A. Appendix

• On April 15, 200, Chesapeake Energy announced a cash tender offer to acquire Bronco Drilling for $11 per share.
• Bronco owns and operates a fleet of 22 land drilling rigs, all of which are currently working (including three under contract to Chesapeake)

Fleet Overview Transaction Analysis

Bronco Acquisition Overview

Oil and Gas Upstream

Irion Minerals, LLC

September 12, 2011 2:30 pm – 4:00 pm Brock Morris and Stephen Dexter

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Irion Minerals, LLC

Projected Investment Returns by Year

Irion Minerals LLC Exit Analysis ($'000) ($ in thousands)

Dec‐11 Dec‐12 Dec‐13 Dec‐14 Dec‐15 Dec‐16 Dec‐17 Dec‐18 Dec‐19 Dec‐20

Exit year Yearly Cash Flow $1,008 $4,678 $7,153 $8,498 $8,961 $5,069 $3,248 $2,382 $1,850 $1,483 Net Proved Reserves (MBoe) 935.8 864.0 759.5 636.9 508.3 432.0 379.5 338.4 304.2 274.9 Net Production (Boe/d) 76.7 249.0 312.6 353.3 284.1 169.3 126.7 102.6 86.8 75.4 % PDP Reserves 17.8% 34.3% 54.2% 79.9% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Exit Assumptions (1) Proved Reserves ($/Boe) $6.94 $10.55 $15.05 $17.73 $17.73 $17.73 $17.73 $17.73 $17.73 $17.73 Producing ($/Boed) $111,325 $111,988 $94,538 $89,062 $89,062 $89,062 $89,062 $89,062 $89,062 $89,062 PV Discount Rate 22.4% 19.9% 16.5% 12.2% 8.0% 8.0% 8.0% 8.0% 8.0% 8.0% % value captured 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Exit Value Weightings Reserves 33% $6,496 $9,119 $11,427 $11,292 $9,013 $7,660 $6,729 $6,000 $5,394 $4,874 Production 33% $8,535 $27,885 $29,552 $31,469 $25,301 $15,076 $11,282 $9,139 $7,727 $6,715 PV of Reserve Report Cash Flows 33% $9,963 $14,702 $18,607 $21,900 $21,742 $17,995 $15,855 $14,450 $13,489 $12,838 Weighted Value 100% $8,331 $17,235 $19,862 $21,554 $18,685 $13,577 $11,289 $9,863 $8,870 $8,143 Net Debt (251) ‐ (683) (2,700) (7,881) (12,950) (16,198) (18,581) (20,430) (21,913) Net Equity Value Reserves $6,747 $9,119 $12,109 $13,993 $16,894 $20,610 $22,927 $24,580 $25,824 $26,787 Production $8,786 $27,885 $30,234 $34,170 $33,182 $28,026 $27,481 $27,719 $28,157 $28,628 PV of Reserve Report Cash Flows $10,214 $14,702 $19,289 $24,601 $29,623 $30,945 $32,053 $33,030 $33,919 $34,751 Weighted Value $8,583 $17,235 $20,544 $24,254 $26,566 $26,527 $27,487 $28,443 $29,300 $30,056 Invested Equity 6,500 7,511 7,520 7,520 7,520 7,520 7,520 7,520 7,520 7,520 Irion Minerals LLC Exit Valuation Analysis (2) ROI Reserves 2.2x 2.2x 2.6x 2.9x 3.2x 3.7x 4.0x 4.3x 4.4x 4.6x Production 2.5x 4.7x 5.0x 5.5x 5.4x 4.7x 4.6x 4.7x 4.7x 4.8x PV of Reserve Report Cash Flows 2.7x 3.0x 3.6x 4.3x 4.9x 5.1x 5.3x 5.4x 5.5x 5.6x Weighted Value 2.5x 3.3x 3.7x 4.2x 4.5x 4.5x 4.6x 4.8x 4.9x 5.0x IRR Reserves 25.0% 24.4% 25.4% 24.3% 24.0% 23.8% 22.8% 21.6% 20.4% 19.3% Production 29.9% 47.9% 41.4% 37.5% 32.6% 27.2% 24.5% 22.6% 21.1% 19.8% PV of Reserve Report Cash Flows 33.1% 33.2% 32.9% 32.3% 31.0% 28.3% 26.1% 24.2% 22.6% 21.2% Weighted Value 29.5% 36.5% 34.0% 32.1% 29.6% 26.6% 24.5% 22.9% 21.4% 20.2% Average MOIC 2.5x 3.3x 3.7x 4.2x 4.5x 4.5x 4.6x 4.8x 4.9x 5.0x Average IRR 29.4% 35.5% 33.4% 31.6% 29.3% 26.5% 24.5% 22.8% 21.4% 20.1% (1) Exit multiples based on a precedent transaction comps which are correlated to % PDP Reserves & PV Discount Rates which are correlated to % PDP Reserves (2) IRRs and ROIs reflect $7.478mm distribution made in 1Q 2011.

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Estimated Period-Over-Period Value Accretion

Estimated Period‐Over‐Period Value Accretion of Irion Minerals, LLC Investment ($ in thousands) 6/30/11 YE 2011 YE 2012 YE 2013 YE 2014 YE 2015 FAS Value

• Est. Value
• Est. Value
• Est. Value
• Est. Value
• Est. Value

Period End Valuation (Weighted Value) $6,660 $8,583 $17,235 $20,544 $24,254 $26,566 Less: Incremental Capital Invested $0 $0 (1,011) (9) ‐ ‐ Net Period End Valuation (Weighted Value) $6,660 $8,583 $16,224 $20,535 $24,254 $26,566 Annualized Period‐Over‐Period Growth / (Decline) NA 66.07% 89.04% 26.57% 18.11% 9.53%

$0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 6/30/11 YE 2011 YE 2012 YE 2013 YE 2014 YE 2015 QEP Exit Assumption ‐ 12/30/2012

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Major Assumptions Behind Exit Analysis

Major Assumption Category Modeled Assumption Risks Related to Assumption Upside Related to Assumption

Wells Drilled / Development Plan 49 Wells Drilled on 11,426 Gross Acres (~233 Acre Spacing) [See Drilling Schedule Below]

• QEP

is not in control

• ver

the pace

• f

development

• EOG has stated that they intend to more slowly

develop the Munson acreage (~27 of 49 wells) due to lease related issues

• EOG

could possibly accelerate the pace

• f

development (relative to QEP’s forecast)

• Development of the upper or lower Wolfcamp

shale sections would substantially increase the number of locations to develop Reserves (EUR / Well) 271 Mboe Type Curve

• Minimal production history is available from very

few wells

• As a result, there is substantial risk in the type

curve assumptions being utilized for economics

• EOG has publically hinted at an upward bias

relative to their ~270 Mboe / well type curve

• AREX has publically announced a 450 Mboe type

curve for the play Commodity Prices 2011 - $93.56 / Bbl 2012 - $90.06 / Bbl 2013 - $92.21 / Bbl 2014 - $92.78 / Bbl 2015 - $93.39 / Bbl

• Lower commodity prices would lower asset cash

flows and likely necessitate additional fund capital to fund the development program

• Type Well PV-10 Breakeven Price = ~$60.00/ Bbl
• Improving

commodity prices would enhance economics of investment Assumed Exit Multiples Reserves - $6.94 / Proved Boe – $17.73 / Proved Boe Production - $89,062 / Boed – $111,325 / Boed Present Value – PV-22.4% to PV- 8.0%

• EOG (most logical buyer for assets) is historically

not an aggressive acquirer of producing assets

• Buyer

universe for small, non-op interest is limited vs. buyers for operated assets

• Financial buyer would have a more difficult time

ascribing value to upside opportunities

• Size of the asset could limit interest from quality

sell side advisors, which could impair the efficiency of the marketing process

• MLP buyer could likely take a more aggressive

approach in valuing the assets

• Economies
• f

scale (and resulting superior valuations) could be realized by adding the Irion assets to a marketing process for Prize Petroleum, LLC

2 4 6 8 10 12 14 2011 2012 2013 2014 2015 Wells Drilled / Year

Irion Minerals LLC Modeled Development Program

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Additional Considerations Regarding Exit Timing

Exit Valuation Considerations

• Successful testing of the Upper and Lower Wolfcamp shale sections could add significant, realizable

upside to the Irion Minerals assets. Timing and number of these upper and lower Wolfcamp shale tests must be taken into consideration when contemplating the timing of an exit event.

• QEP is actively evaluating opportunities to increase its exposure to the horizontal Wolfcamp shale play.

Execution on any of these expansion opportunities could potentially extend the exit horizon for the Irion investment as: (i) adequate testing / development of any new acreage would be necessary to maximize value and (ii) separate monetization events of existing and new Wolfcamp shale assets would not take advantage of potential premium value associated with asset scale.

• Most buyers of non-operated, small working interest are focused on PDP cash flows and typically do not

ascribe significant value to undeveloped upside. Accordingly, the balance of producing vs. non-producing reserves must be considered when contemplating an exit.

Potential Impediments to Investment Exit

• Nature of assets may limit universe of potential buyers as many strategic acquirers don’t actively pursue

non-operated assets.

• Size of assets will likely limit QEP’s choice of advisors when marketing the assets of Irion Minerals. A

quality advisor capable of running an efficient, competitive process is key in maximizing value upon exit.

E&P Team’s Thoughts & Recommendation

• Allow the upside story of the Upper and Lower Wolfcamp shale section to play out prior to putting the Irion

Minerals assets on the market.

• If timing is compatible, consider adding the Irion Minerals assets to the asset package associated with the

monetization of Prize Petroleum.

• Operated assets of Prize Petroleum will attract a much larger and diverse set of potential buyers
• Size of Prize’s assets will draw attention from top tier of sell-side A&D advisors

C t f it l d t f MLP b (l i l b f P i ’ t ) ld l d t i d

Prize Petroleum, LLC

Investment Level Valuation & Exit Assessment

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Prize Petroleum, LLC

Projected Investment Returns by Year

Prize Petroleum, LLC Management Milestons & Resulting Exit Analysis ($'000) Prize Petroleum LLC Forecasted Equity Returns ($ in thousands)

Dec‐11 Dec‐12 Jun‐13

($ in thousands)

Dec‐11 Dec‐12 Jun‐13

Exit year Exit year Prize Management Goals / Milestones QEP Equity Ownership % 52.71% 52.71% 52.71% Daily Production (Boe/d) 1,477 1,835 2,000 Proved Reserve (Mboe) 15,857.0 16,754.6 17,203.4 QEP Net Exit Values (Equity Values) (2) Tier 1 $50,259 $66,778 $74,407 Exit Multiples ‐ MLP Production Based Exit Multiples (1) Tier 2 $55,984 $72,404 $78,604 $95,000 / Flowing Boed $140,315 $174,325 $190,000 Tier 3 $61,027 $78,030 $83,629 $100,000 / Flowing Boed $147,700 $183,500 $200,000 Tier 4 $66,071 $81,297 $89,015 $105,000 / Flowing Boed $155,085 $192,675 $210,000 Tier 5 $71,114 $86,430 $94,401 $110,000 / Flowing Boed $162,470 $201,850 $220,000 $115,000 / Flowing Boed $169,855 $211,025 $230,000 Forecasted QEP Rates of Return Tier 1 ‐0.1% 5.9% 7.4% Exit Multiples ‐ MLP Reserve Based Exit Multiples (1) Tier 2 2.7% 7.6% 8.5% $10.00 / Proven Boe $158,570 $167,546 $172,034 Tier 3 5.0% 9.3% 9.8% $11.00 / Proven Boe $174,427 $184,301 $189,237 Tier 4 7.1% 10.2% 11.1% $12.00 / Proven Boe $190,284 $201,055 $206,441 Tier 5 9.2% 11.6% 12.3% $13.00 / Proven Boe $206,141 $217,810 $223,644 $14.00 / Proven Boe $221,998 $234,564 $240,847 Forecasted QEP Raturn on Investment Tier 1 1.00x 1.32x 1.47x Average Gross Exit Values (Enterprise Values) Tier 2 1.11x 1.43x 1.56x Tier 1 $149,443 $170,936 $181,017 Tier 3 1.21x 1.55x 1.66x Tier 2 $161,064 $183,900 $194,619 Tier 4 1.31x 1.61x 1.76x Tier 3 $172,685 $196,865 $208,220 Tier 5 1.41x 1.71x 1.87x Tier 4 $184,306 $209,830 $221,822 (2) QEP Net Exit Values account for distributions to management incentive Tier 5 $195,927 $222,795 $235,424 Forecasted Net Debt $51,000 $36,000 $28,500 Average Gross Exit Values (Equity Values) Tier 1 $98,443 $134,936 $152,517 Tier 2 $110,064 $147,900 $166,119 Tier 3 $121,685 $160,865 $179,720 Tier 4 $133,306 $173,830 $193,322 Tier 5 $144,927 $186,795 $206,924 (1) Base case (Tier III) multiples based on median values from comparable transaction comps (see last page of presentation)

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Prize Petroleum, LLC

Estimated Period-Over-Period Value Accretion

Estimated Period‐Over‐Period Value Accretion of Prize Petroleum, LLC Investment ($ in thousands) 6/30/2011 YE 2011 YE 2012 6/30/2013 FAS Value

• Est. Value
• Est. Value
• Est. Value

Period End Valuation (Tier III) $58,819 $61,027 $78,030 $83,629 Less: Incremental Capital Invested $0 ‐ ‐ Net Period End Valuation (Tier III) $58,819 $61,027 $78,030 $83,629 Annualized Period‐Over‐Period Growth / (Decline) NM 7.65% 27.86% 14.87% (1) QEP's Exit Assumption assumes that Prize is able to further bolster equity value through accretive, bolt‐on acquisitions

$0 $20,000 $40,000 $60,000 $80,000 $100,000 $120,000 6/30/2011 YE 2011 YE 2012 6/30/2013 QEP Exit Assumption ‐ 12/30/2013 (1)

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Major Assumptions Behind Exit Analysis

Major Assumption Category Modeled Assumption Risks Related to Assumption Upside Related to Assumption

Production Increases Reserve Report Production + Low Resistivity Woodbine / Subclarksville Waterflood Contribution [Production Breakdown Below]

• Production

assumes unrisked execution

• f

production enhancement and undeveloped

• pportunities in the 12/31/10 Reserve Report.
• Low

Resistivity Woodbine / Subclarksville production wedge is largely not in the reserve report, is in the very early stages of testing, and the ultimate potential of these opportunities is unknown.

• Low

Resistivity Woodbine / Subclarksville developments have the potential to be substantial and contribute more meaningfully to future production.

• Initial focus
• n the Neches field has kept

management from prioritizing production enhancement of the Homer and Rich fields.

• The

Prize team is currently focused

• n

accretive, bolt-on acquisitions that could contribute significant, incremental production volumes. Reserves Management has goal of increasing proven reserves by 6% per annum

• Prior

management’s results in executing undeveloped and non-producing opportunities generally underperformed reserve report estimates.

• Additional infrastructure work is necessary to

execute on all identified reserve additions.

• Low

Resistivity Woodbine / Subclarksville developments could represent a meaningful increase in reserve report volumes.

• The

Prize team is currently focused

• n

accretive, bolt-on acquisitions that could meaningfully add to Prize’s reserves. Assumed Exit Multiples Precedent transactions in OK, TX, and LA between $50mm and $500mm since 2005; R/P >20 years; and % Oil > 65%.

• Average 5 year strip of precedent transactions =

$84.10 / Bbl. Multiples will likely degrade if prices dip below this average.

• Rising interest rates would likely impact MLP’s

(logical buyers) cost

• f

capital, negatively affecting valuation.

• Long R/P nature of assets… production multiple

values could limit buyer’s ability to give full value based

• n

assets’ PV and reserve metric valuation.

• Multiple expansion at prices above the average

5 year strip of precedent transactions = $84.10 / Bbl.

• MLP’s

ability to pay (publically traded valuations) is, on average, substantially higher than precedent transaction values ($20.66 / Proven Boe & ~$150,000 / Flowing Boed as of 6/30/11).

• Acquisitions

could improve exit valuation if accretive and if they serve to shorten Company R/P.

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Additional Considerations Regarding Exit Timing

Exit Valuation Considerations / Milestones enhanced value of the assets upon completion. This work needs to be completed before an educated buyer could give Prize full value for undeveloped and non-producing opportunities in the reserve report.

• To date, Prize management has been focused on optimizing
• perations

and exploiting upside within the Neches field. Sufficient time to do the same work on the Homer and Rich fields would likely lead to additional enhanced value for Prize upon exit.

• Prize management is currently evaluating and testing the

potential associated with a low resistivity zone at the top of the Woodbine section and the re-initiation of a Subclarksville waterflood that was abandoned by Exxon in the mid-to-late 1960’s. Either of these projects could meaningfully increase reserves and production in the Neches field.

• Prize management is actively engaged in acquisitive business

development and has recently submitted offers on a number of property packages. Major theme of the business development efforts to date has been to shorten the R/P of the Company’s asset base by acquiring shorter-lived, out-of-favor natural gas assets. Potential Impediments to Investment Exit

• The structure of Prize management / Redman Resources

incentives structure could lead to some misalignment with QEP at some very specific points in the spectrum of returns (primarily related to two “catch-up” points in the distribution waterfall).

• Rising interest rate environment could degrade the cost of

capital for E&P MLPs (logical acquirer for Prize’s assets) which would lead to lower valuations for the asset. E&P Team’s Thoughts & Recommendation

• Need to test and quantify the upside story of the low resistivity

Woodbine and the Subclarksville waterflood to ensure maximum potential value upon exit.

• To enhance value of existing assets upon exit, the infrastructure

projects at the Neches and Homer fields need to be completed and need enough time to adequately demonstrate the associated cost savings.

• Allow Prize management enough time to execute and integrate

bolt-on, accretive acquisition opportunities that could help justify higher valuations from potential buyers when considering acquisition multiples.

• Prior to monetization, need to dedicate sufficient resources to
• ptimizing and exploiting upside at both the Homer and Rich

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Appendix A: Precedent Transactions Analysis

Average Transaction Proved % Proved Proved Reserve TV/Daily Boe 5 Yr. Strip Date Buyer Seller Location Value Reserves % Oil Developed R/P Value Produced @ Transaction (MMBoe) (Years) ($/Proved Boe) ($/boed) Feb‐11 Linn Energy LLC Undisclosed Permian $238.00 14.0 88.0 48.0 32.2 $16.98 $144,242.40 $99.81 Oct‐10 Berry Petroleum Company Undisclosed (Various) Mid‐Continent $180.00 N/A 76.0 N/A N/A N/A $150,000.00 $87.12 Sep‐10 Linn Energy LLC Undisclosed (Three parties) Mid‐Continent $352.20 30.0 72.0 23.3 24.9 $11.74 $106,727.27 $84.35 Aug‐10 Energen Corporation; Energen Resources Corporation Undisclosed private company Mid‐Continent $185.00 18.0 86.6 10.9 54.7 $10.29 $205,555.56 $80.27 Jul‐10 Linn Energy LLC Undisclosed Gulf Coast $95.00 8.0 93.0 100.0 24.4 $11.88 $105,555.56 $81.69 Jul‐10 Linn Energy LLC Undisclosed Mid‐Continent $90.00 7.0 78.0 28.0 20.2 $12.86 $94,736.84 $78.93 May‐10 PDC Energy Undisclosed private company Mid‐Continent $75.00 8.5 70.0 N/A 25.9 $8.82 $83,333.33 $78.09 Jan‐10 Berry Petroleum Company Undisclosed private company Mid‐Continent $126.00 11.2 85.0 23.0 23.6 $11.25 $96,923.08 $90.46 Dec‐09 Denbury Resources Incorporated Wapiti Energy LLC Gulf Coast $409.55 20.0 90.0 100.0 21.9 $20.48 $163,820.80 $88.86 Sep‐09 Pioneer Southwest Energy Partners LP Pioneer Natural Resources Company Mid‐Continent $171.20 18.9 85.0 37.0 39.8 $9.06 $131,692.31 $77.21 Aug‐09 Linn Energy LLC Forest Oil Corporation Mid‐Continent $113.70 10.0 86.0 58.0 20.3 $11.37 $84,222.22 $83.02 Dec‐07 Mariner Energy Inc Undisclosed Mid‐Continent $122.50 16.0 75.0 45.0 35.1 $7.66 $98,000.00 $87.52 Dec‐07 Linn Energy LLC Lamamco Drilling Company Mid‐Continent $552.00 50.0 88.0 70.0 34.2 $11.04 $138,000.00 $87.13 Dec‐07 Windsor Permian LLC Undisclosed Mid‐Continent $85.00 6.9 87.0 23.0 23.6 $12.32 $106,250.00 $85.46 Dec‐07 Gulfport Energy Corporation Undisclosed Mid‐Continent $85.00 6.9 87.0 23.0 23.6 $12.32 $106,250.00 $85.46 Nov‐07 Pioneer Natural Resources Company Cimarex Energy Co Mid‐Continent $90.00 15.0 100.0 20.0 58.7 $6.00 $128,571.43 $84.64 Jun‐06 Foothills Resources Inc Texas American Resources Company Gulf Coast $62.00 5.1 97.4 66.1 20.1 $12.08 $88,571.43 $69.77 Deal Count 17 Average $178.36 15.3 84.9 45.0 30.2 $11.63 $119,556.01 84.10 Median $122.50 12.6 86.6 37.0 24.6 $11.56 $106,250.00 84.64 Note: Transactions between $50mm and $500mm in OK, TX, LA since 2005; R/P >20 years; % Oil > 65%. Source: IHS – John S. Herolds.

Deep Gulf Energy, LP

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Deep Gulf Energy, LP

Projected Investment Returns (DGE Management Projections)

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Deep Gulf Energy, LP

Estimated Value Accretion

Estimated Value Accretion of Deep Gulf Energy, LP Investment ($ in thousands) 6/30/2011 YE 2013 YE 2013 FAS Value (1) All Dry Holes All Successful Period End Valuation $16,500 $19,140 $28,833 Less: Incremental Capital Invested $0 $0 $0 Net Period End Valuation $16,500 $19,140 $28,833 Annualized Period‐Over‐Period Growth / (Decline) NA 6.12% 25.02% (1) 6/30/2011 FAS Value +$3.0mm of distributions previously received from DGE I.

$0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 6/30/2011 YE 2013 ‐ All Dry Holes YE 2013 ‐ All Successful QEP Exit Assumption ‐ 12/30/2013 (1)

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Major Assumptions Behind Exit Analysis

Major Assumption Category Modeled Assumption Risks Related to Assumption Upside Related to Assumption

Operating & Capital Assumptions (Incremental Production, Reserves, & Capital) Danny II (50% POS) & Perseides (50% POS) are drilled in November 2011 & September 2012, respectively

• Danny II (50% POS) & Perseides (50% POS)

could be unsuccessful exploration wells and cost could be in excess of budgeted levels.

• Issues with permitting could cause delays in

drilling the Perseides well.

• Natural disasters (hurricanes) could result in

damaged infrastructure and substantial downtime for currently producing wells.

• Water drive reservoirs increases risks associated

with forecasting well results and, consequently, future cash flows.

• Wells (both producing and exploration wells)

could perform better than current forecasts. Commodity Prices [See Charts Below]

• Future realized commodity prices could come in

below strip pricing. However, 46% of remaining 2011 and 28%

• f

2012 gas production is currently hedged at $5.50 and $5.27 respectively.

• DGE’s forward cash flow projections do not factor

in ~$14.00 LLS premium that they are currently receiving relative to NYMEX prices. Assumed Exit Multiples Remaining Production is sold at PV-25% in 2013

• May be difficult to run a competitive auction

process surrounding short lived, fully developed GOM assets.

• PV-25% is a very punitive discount rate on an

assumed exit.

• In calculating exit scenarios, no value has been

ascribed to the Mississippi Lime assets by DGE management.

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Additional Considerations Regarding Exit Timing

Exit Valuation Considerations / Milestones

• DGE I has three more projects left in its portfolio (Danny II, Perseides, and Mississippi Lime) and the

ultimate timing of the exit from this investment will be driven by execution (or lack there of) on these three remaining initiatives.

• QEP is a 4.82% owner of DGE I and FRC is the controlling shareholder of the Company. QEP’s minority

stake in the business limits our ability to control the decisions surrounding exit.

Potential Impediments to Investment Exit

• Management’s incentives in DGE I are purely ROI driven, so management is incentivized to generate the

maximum profits from the investment regardless of the resulting IRR for the equity sponsor.

• This dynamic is likely leading to a Board level decision surrounding the timing of an exit event with

management potentially pushing for an exit date beyond 2013.

E&P Team’s Thoughts & Recommendation

• Potential upside and sunk costs associated with the three remaining projects justifies attempted execution

prior to any contemplated exit event.

• Attempt to influence, as best as possible, future discussions surrounding the timing and avenues for exit for

the Company from our position on the Board of Directors.

• DGE & QEP need to seek advice on options available for monetizing DGE I. More specifically, (i) structural

alternatives to an outright sales process, (ii) universe of interested parties given the nature of the assets, and (iii) reasonable valuation expectations for the assets.

Deep Gulf Energy II, LLC

Investment Level Valuation & Exit Assessment

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Deep Gulf Energy II, LLC

Projected Investment Returns (DGE II Management Projections)

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Deep Gulf Energy II, LLC

Estimated Value Accretion

Estimated Value Accretion of Deep Gulf Energy II, LLC Investment ($ in thousands) 6/30/2011 YE 2016 YE 2016 FAS Value All Dry Holes All Successful Period End Valuation $9,980 $10,284 $63,733 Less: Incremental Capital Invested $0 ($424) ($1,484) Net Period End Valuation $9,980 $10,708 $62,249 Annualized Period‐Over‐Period Growth / (Decline) NA 1.29% 39.41%

$0 $10,000 $20,000 $30,000 $40,000 $50,000 $60,000 $70,000 6/30/2011 YE 2016 ‐ All Dry Holes YE 2016 ‐ All Successful QEP Exit Assumption ‐ 12/30/2015 (1)

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Major Assumptions Behind Exit Analysis

Major Assumption Category Modeled Assumption Risks Related to Assumption Upside Related to Assumption

Operating & Capital Assumptions (Incremental Production, Reserves, & Capital)

Prospect POS Spud Date

• All
• f

the wells remaining in inventory are exploratory in nature with substantial risks related to size, costs, and timing.

• Issues with permitting and rig availability could

cause delays in drilling DGE II’s remaining inventory of projects.

• Natural disasters (hurricanes) could result in

damaged infrastructure and substantial downtime for currently producing wells.

• Water drive reservoirs increases risks associated

with forecasting well results and, consequently, future cash flows.

• Wells (both producing and exploration wells)

could perform better than current forecast.

Danny II 50% Nov-11 Perseides 50% Nov-11 Marmalard 50% Dec-11 SOB 2 50% Sept-12 Troubador 70% Mar-12 Leatherneck 33% June-12

Commodity Prices [See Charts Below]

• Future realized commodity prices could come in

below strip pricing. However, DGE II plans to mitigate some of this risk through an active hedging program.

• DGE’s forward cash flow projections do not factor

in ~$14.00 LLS premium that they are currently receiving relative to NYMEX prices. Assumed Exit Multiples Remaining Production is sold at PV-25% in 2016

• Depending

upon the status

• f

DGE II’s exploration portfolio, it may be difficult to run a competitive auction process surrounding short lived, fully developed GOM assets.

• PV-25% is a very punitive discount rate on an

assumed exit.

• In calculating exit scenarios, no value has been

ascribed to the Mississippi Lime assets by DGE II management.

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Additional Considerations Regarding Exit Timing

Exit Valuation Considerations / Milestones

• DGE II is currently sitting at a 0.65x ROI with the future returns of the Company solely

dependent upon the success of its upcoming exploration program.

• The overall decrease in value since original investment is primarily attributable to (i)

decrease in natural gas prices, (ii) delays associated with infrastructure damage from Hurricane Ike, (iii) overestimation of reserves at the Noonan project, and (iv) mechanical issues related to the Bass Lite project.

• Contingent upon the success of future exploration, DGE II anticipates requiring additional

capital / liquidity of between $8.6mm (all dry holes) and $43.1mm (Perseides, SOB 2, and Marmalard successful). If the shortfall was covered 100% by equity holders (and QEP decided to fund its share of the shortfall), QEP would have the opportunity to fund between $424,000 and $2,118,650 to cover its portion of additional liquidity for the business.

• QEP is a 4.92% owner of DGE II and FRC is the controlling shareholder of the Company.

QEP’s minority stake in the business limits our ability to control the decisions surrounding exit.

Potential Impediments to Investment Exit

• Management’s incentives in DGE II are purely ROI driven, so management is incentivized

to generate the maximum profits from the investment regardless of the resulting IRR for the equity sponsor.

E&P Team’s Thoughts & Recommendation

• Success of DGE II is contingent upon the results of its ongoing exploration program.

Accordingly, success in the go-forward program is paramount to generating positive returns

• n the investment.
• Attempt to influence, as best as possible, future discussions surrounding the strategic

direction and exit alternatives for the investment from our position on the Board of Directors.

• FRC will likely present to QEP a plan for addressing the forecasted liquidity shortfall in the

next several weeks and the E&P team will be presenting our thoughts on this plan for Fund II Investment Committee consideration.