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1 Strong simple balance sheet Total Assets: $7.3 billion - PowerPoint PPT Presentation

Dec 04, 2022 •374 likes •594 views

1 Strong simple balance sheet Total Assets: $7.3 billion Total Debt: $1.6 billion ($510 million RC, $1,078 million senior notes) Total Equity: $3.3 billion Conservative leverage Debt/EBITDA: 1.2x (EBITDA is 3

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  2.  Strong “simple” balance sheet • Total Assets: $7.3 billion • Total Debt: $1.6 billion ($510 million RC, $1,078 million senior notes) • Total Equity: $3.3 billion  Conservative leverage • Debt/EBITDA: 1.2x (EBITDA is 3 rd quarter 2011 “annualized”) • Debt/Cap: 32% • Debt ratings: Ba1/BB+ (Stable/Stable) • No debt maturities until 2016  New $1.5 billion revolving credit Loan Pricing Grid • $2.0 billion accordion feature • Debt/EBITDA Loan Unused 5 year term (two one-year extensions) • < 1.00X L+150 0.300% Leverage based pricing grid • 1.00x – 1.75X L+175 0.325% $510 million drawn at 9/30 • 1.75x – 2.50X L+200 0.350% Two financial covenants • 60% Debt/Cap > 2.50X L+225 0.375% • 3.5X EBITDA total debt cap 2

  3.  Assets generate strong cash flow • E&P LTM EBITDA: $999 million (9 months 2011: $757 MM) • Midstream LTM EBITDA: $285 million (9 months 2011: $233 MM) • Total LTM EBITDA: $1,295 million (9 months 2011: $996 MM)  Capital program – designed to be “at or around EBITDA” • $1,500 million plan for 2012 • Drives mid-teens production and EBITDA growth from identified, in-house inventory of projects • Minimum 15% ATAX ROR for capital allocation  Low cost structure • Competitive advantage in core plays • Operating costs among the lowest in the industry  Hedging program • Target: 50% of forecasted production • E&P is 44% hedged for 2012: 50% natural gas, 32% oil, 11% NGL • Hedging NGL’s for midstream volumes 3

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  5. $1,600 $1,500 Revolver Available Revolver Capacity $1,400 Drawn Revolver Maturity Amount % of Total Coupon Duration (yrs) Long Term Notes 9/1/2016 176,843,000 16.4% 6.050% 4.81 4/1/2018 138,648,000 12.9% 6.800% 6.39 $1,200 3/1/2020 137,968,000 12.8% 6.800% 8.31 990.0 3/1/2021 625,000,000 58.0% 6.875% 9.31 12/4/2019 1,078,459,000 100.0% 6.720% 8.07 $1,000 $800 6.875% ~2.0% 625.0 $600 510.0 $400 6.05% 6.80% 6.80% $200 138.6 138.0 176.8 $- 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 5

  6. $500 $450 353.7 336.6 $400 305.8 298.5 297.5 1.6 $350 2.0 276.0 268.5 3.7 2.4 84.8 2.6 $300 86.9 1.5 2.6 61.4 48.9 52.4 $250 52.1 50.5 $200 $150 267.3 247.7 246.0 242.4 242.0 222.4 215.4 $100 $50 $- 1Q 10 2Q 10 3Q 10 4Q 10 1Q 11 2Q 11 3Q 11 Energy Field Services Marketing 6

  7. 1 Includes unrealized gain (loss) on basis-only swaps, separation costs and early debt retirement expenses 7

  8. ($MM) 2010: Midstream: Construction of Iron 2,137 Horse, Blacks Fork II gas 2008: $655 MM plants and NW LA Cotton Valley / gathering ($268 MM) Haynesville acquisition 1,500 1,500 1,485 1,350 1,333 1,311 1,198 1,165 1,141 891 839 Actual EBITDA or EBITDA Guidance CAPEX 8

  9. 25% Return on Capital Employed 20% (TTM EBITDA / Gross PP&E) 15% 10% 5% 0% 1Q 09 2Q 09 3Q 09 4Q 09 1Q 10 2Q 10 3Q 10 4Q 10 1Q 11 2Q 11 3Q 11 QEP Energy QEP Field Services QEP Resources 9

  10. EBITDA 2012 guidance as of 11/14/11: ($MM/yr) • EBITDA $1.45 B to $1.55 B • 305 to 310 Bcfe production 1,500 * • Capital investment of $1.50 B 1,333 * 1,311 • Approximately 44% of 2012 estimated 1,165 1,141 production currently hedged • Assumptions for unhedged 891 production: 738 • NYMEX gas price $3.75 to $4.25/MMBtu • NYMEX oil price $90 to $100/Bbl • Rockies basis: $0.20 to $0.15/MMBtu • Midcontinent basis: $0.20 to $0.15/MMBtu * midpoint of guidance 10

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  12.  Overview  Northern Region Plays • Vincent Rigatti, General Manager, Northern Region • Paul Matheny, Vice President and Chief of Staff  Southern Region Plays • Jeff Thompson, Division Reservoir Engineer • Linden Bailey, Division Reservoir Engineer  Other QEP Energy officers here today: • Austin Murr, Vice President, Land and Business Development • Jeff Tommerup, Vice President, Eastern Midcontinent Division • Michael Penner, Vice President, Western Midcontinent Division 12

  13. QEP Resources QEP QEP Field QEP Energy Services Marketing Exploration & Gathering & Marketing & Production Processing Gas Storage Southern Northern Region Region Haynesville/ Pinedale Legacy Uinta Midcont Cotton Valley 13

  14.  Plays being discussed for the first time: • Liquids-rich gas plays: • Uinta Basin Red Wash Lower Mesaverde • Vermillion Basin Almond • Oil Plays: • Uinta Red Wash (Green River) • Powder River Basin (Sussex, Shannon, Niobrara, Frontier) • Western Oklahoma (Marmaton, Tonkawa)  Ongoing development: • Bakken/Three Forks • Pinedale • Woodford Cana • Haynesville 14

  15. Powder ND Pinedale River Basin Anticline Northern Region: WY Bakken/TFS Gross Acres: 2.59 MM Net Acres: 1.32 MM UT (78% HBP or HBU) Vermillion Uinta Basin CO Marmaton, Tonkawa Northern Region Southern Region: OK Gross Acres: 1.60 MM Woodford Cana Net Acres: 0.64 MM Southern Region (86% HBP) Granite Wash TX LA Liquids-rich gas plays Total: Oil plays Gross Acres: 4.19 MM Dry gas plays Haynesville Net Acres: 1.96 MM (81% HBP or HBU) Approximately 34,000 net acres (1.8%) will expire in 2012 in the 15 15 absence of development

  16. Proved Reserves Net Production (Bcfe) 307.5 (Bcfe/yr) 272 3,031 2,747 229 171 190 2,218 1,868 130 140 1,631 2011 Guidance: 270 – 274 Bcfe 2012 Guidance: 305 – 310 Bcfe 16

  17. $1.48 B $1.35 B $1.50 B 11% 18% 7% 9% 14% 6% Field Services 3% 8% 23% All Other 12% 8% 2% Oil Plays 6% 12% 6% 19% Woodford Cana Uinta RW MV 19% 20% Bakken/TFS 20% Pinedale 30% 28% Haynesville 19% 2010 Capital 2011 Capital 2012 Capital All Other: Vermillion Almond, Budget Budget Granite Wash, and land, seismic, general plant, etc. 17

  18. 2012 Avg Avg Gross Avg Well Cost Play Operated Rig EUR (Bcfe or BTAX ROR (MM$) Count MBoe) Western OK 2 $3.9 165 * 95% Oil Vermillion 0.25 $1.8 1.9 45% Almond Uinta Red Wash Lower 2 $2.1 2.1 42% MV Pinedale 6 $3.8 4.6 38% Powder River 0.5 $6.7 325 * 34% Basin Oil Bakken/TFS 3 $9.5 550 * 26% Woodford 2 $8.3 5.5 23% Cana Haynesville 2 $9.1 6.0 20% * In MBoe 18

  19. Gas Liquids 11% 14% 20% 89% 86% 80% 2010 2011E 2012F 19

  20. WILLISTON BASIN Bakken PINEDALE Probable (Bcfe): 195 Probable (Bcfe) 1,492 Possible (Bcfe): 526 Possible (Bcfe): 105 Resource Potential (Bcfe): 34 Resource Potential (Bcfe): 766 POWDER RIVER/DJ BASINS GREATER GREEN RIVER BASIN Probable (Bcfe): - Possible (Bcfe): - Probable (Bcfe): 681 Resource Potential (Bcfe): 1,077 Possible (Bcfe): 2,007 Resource Potential (Bcfe): 5,984 TX PANHANDLE Granite Wash UINTA BASIN Probable (Bcfe): 88 Probable (Bcfe): 291 Possible (Bcfe): 28 Possible (Bcfe): 1,190 Resource Potential (Bcfe): 103 Today’s Discussion Will Cover Resource Potential (Bcfe): 8,920 W. OKLAHOMA N. PARADOX BASIN Woodford 82% of Probable Probable (Bcfe): - Probable (Bcfe): 125 Possible (Bcfe): - Possible (Bcfe): 598 Resource Potential (Bcfe): 948 Resource Potential (Bcfe): 455 76% of Possible N.W. LOUISIANA Total 3P + Resource Estimates: 11% of Resource Haynesville Proven 3,031 Bcfe Probable (Bcfe): 829 Possible (Bcfe): 1,433 Probable 3,701 Bcfe Resource Potential (Bcfe): 159 Possible 5,887 Bcfe Resource 18,446 Bcfe Probable, Possible, and Resource estimates (as of May 1, 2010) not prepared on basis of SEC guidelines relative to commodity prices and timing of development 20

  21. Inventory Life at 2012 Activity Levels (Years) 80 75 70 60 50 40 30 23 22 20 14 11 9 10 0 Bakken/TFS PRB/W. OK Pinedale Red Wash Woodford Haynesville Oil Lower MV Cana 21

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