Opportunities in Conventional Gas Peter s and Co. Toronto September 16, 2009 Power to Perform Forward-Looking Statements Certain information regarding PET in this presentation may constitute forward-looking statements under applicable securities laws. Forward-looking statements may be identified by words like forecast, estimated, expected or similar expressions. These forward looking statements are based on certain assumptions that involve a number of risks and uncertainties and are not guarantees of future performance. Risks and uncertainties may include, without limitation, risks associated with gas exploration, development, exploitation, production, marketing and transportation, changes to the proposed royalty regime prior to implementation and thereafter, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, delays in projects and/or operations resulting from surface conditions, wells not performing as expected, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. These forward looking statements are based on certain assumptions that involve a number of risks and uncertainties and are not guarantees of future performance. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements as a result of changes in PET s plans, changes in commodity prices, regulatory changes, general economic, market and business conditions as well as production, development and operating performance and other risks associated with oil and gas operations. Furthermore, the forward-looking statements contained in this presentation are made as at the date of this presentation and PET does not undertake any obligation to update publicly or to revise any of the forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
Business Plan CONVENTIONAL SHALLOW GAS NEW VENTURES ASSET OPTIMIZATION ACCRETIVE ACQUISITIONS + Synergistic To Base Assets Unconventional Viking and Colorado Shale GOB technical solutions CO 2 sequestration & storage Gas storage Bitumen land bank West Holden Mannville CBM MAXIMIZE CASH FLOW HEALTHY BALANCE SHEET High Impact Growth Deep Basin exploration MAXIMIZE DISTRIBUTIONS AND UNITHOLDER VALUE Cash Flow Reinvestment SUSTAINABILITY & DISTRIBUTIONS BASE ASSETS GROWTH CASH FLOW DISTRIBUTIONS NEW VENTURES Cash flow for distribution, reinvestment in shallow gas assets for sustainability and investment in New Ventures for growth
Value Creation - The Model Works $/Trust Unit NAV @ Feb 2003 $8.91/Unit $28.00 $24.00 $20.00 $16.00 $12.00 $8.00 $4.00 $0.00 Feb 03 2003 2004 2005 2006 2007 2008 200% 160% 120% 80% 40% 0% Cumulative annual return on initial NAV (%) Distributions to Year end 2008 $13.124/Unit NAV @Year end 2008 $10.63/Unit Year end net asset value @ 5% Annual distributions Year end net asset value plus distributions to date Cumulative rate of return on initial NAV (%) Current distributions - $0.05 per Unit per month Average annual return on NAV = 28% Value growth per Unit since inception = 166% Operations, Assets and Prospect Inventory
PET Operations Profile Fort McMurray Natural Gas Focused Asset Base: 5 Core Producing Areas plus Private Explore Co. Conventional Shallow Gas - Mannville and Devonian Unconventional Gas - Viking Resource Play Deep Basin Tight Gas Resource Plays Rock Creek, Notikewin Grande Prairie Athabasca Current Average Daily Production 145 MMcfe/d (24,333 BOE/d) Recent 2009 Voluntary Production Shut-in 40 MMcfe/d (5,833 BOE/d) Total Production Capability 180-190 MMcfe/d (30,000 BOE/d) Gas over Bitumen Deemed Production 18.5 MMcf/d Edmonton Conventional Shallow Gas Calgary Other Conventional Gas Unconventional Deep Basin Gas Unconventional Shallow Gas Conventional Oil Bitumen Viking P+P Reserves (1) Reserve Life Index (P+P) Undeveloped Land Base (Core Producing Areas) 560.7 Bcfe 8.0 Years 7 Million net acres E&P New Venture Opportunities: NE Alberta Bitumen Resource Exposure 330,000 net acres Elmworth Montney 50,000 net acres Mannville CBM Asset Optimization Strategy Offset annual production through capital investment targeting to maintain production, reserves and opportunities per Unit Balanced Portfolio Opportunity Inventory - Unrisked Reserve Report Prospect Inventory 2008 Year End P + P Reserves = 560.7 Bcfe Unrisked Additional Reserve Potential = 1,601 Bcfe Proved & Probable Undeveloped GOB Recompletions Conventional Proved & Probable Developed Unconventional + Oil Sands Other Captured New Ventures Gas Storage CO 2 Sequestration and Storage Mannville CBM As technical understanding advances risk assessment adjusts and risk-discounted potential grows
Balanced Portfolio Opportunity Inventory Risk Discounted Reserve Report Prospect Inventory 2008 Year End P + P Reserves = 560.7 Bcfe Risk-Discounted Additional Reserve Potential = 345 Bcfe Proved & Probable Undeveloped GOB Recompletions Conventional Proved & Probable Developed + Oil Sands Unconventional New Ventures Gas Storage CO 2 Sequestration and Storage Mannville CBM Booked reserves represent <60% of the risk-discounted reserve potential and value of PET Conventional Shallow Gas
Shallow Gas Asset Base Characteristics Concentrated operating areas in NE and East Central Alberta Predictable production base Manageable base declines (~19%) High netbacks High working interest Infrastructure ownership and operatorship Opportunity inventory for cost-effective production and reserve additions Concentric exploration and development Undeveloped land to feed the prospect inventory Shallow gas asset base well suited to sustainable cash flow distributing model East Central Alberta Conventional Shallow Gas Economics Rate of Return Break-Even Gas Price Source: Peters & Co. (Fall 2008) Great return on investment in $7.00 gas price environment
Conventional Shallow Gas Investment - How Does it Stack Up? Shallow Gas Plays in East Central Alberta have: Highest half cycle and full cycle average rate of return Lowest break-even gas price Most profitable reserve additions (NPV / Mcf 66% higher than average) Lowest risked capital (~$250 - $350K / well) Top Natural Gas Play Types - Western Canada Sedimentary Basin Full Cycle Incremental Well F&D Cost Break-even Index per BOE Rate of NPV 10% NPV/Mcf Price No. Play Type Province (C$/BOE) Return (C$MM) (C$/Mcf) (C$/Mcf) PET - Shallow Gas Alberta $10.27 20% $0.33 $0.78 $4.66 1 Cardium Alberta $11.43 18% $1.15 $0.86 $4.12 16 Montney Horizontal - Kaybob Alberta $11.48 14% $2.39 $0.77 $4.37 8 Edmonton Sands Alberta $14.80 8% $0.23 $0.81 $4.67 10 Generic Gas - Countess/Drumheller Alberta $16.15 5% $0.22 $0.76 $4.87 15 Montney Horizontal - Dawson B.C. $11.40 3% $3.11 $0.63 $4.66 6 Devonian Gas Alberta $7.67 2% $4.90 $0.11 $5.59 2 CBM - Horseshoe Canyon Alberta $21.83 n/a n/a n/a $6.33 9 Foothills Halfway B.C. $9.59 n/a $0.42 $0.18 $5.51 21 Shale Gas Horizontal B.C. $13.23 n/a $2.29 $0.30 $5.40 Note: Rate of return and NPV estimates are based on a C$6.00/Mcf AECO gas price. Incremental wells do not include costs for major facilities, land, and seismic. Source: Peters & Co. The Downside Reserve and value adds per opportunity are relatively small East Central Alberta Conventional Shallow Gas Economics Source: Peters & Co. (June 2009) Investment still warranted if long term gas prices average $6.00/Mcf and cost reduction initiatives persist
Conventional Shallow Gas - Challenges Small prospect size means prospect inventory must be large with many unique entities making it difficult to explain and understand Prospect inventory has limited third party engineering endorsement Drilling locations and even uphole completions generally don t meet criteria for booking under NI 51-101 Limited repeatability = labor intensive technically Difficult for investment community to technically verify scope and risk of prospect inventory Lacks pizzazz for capital markets Smaller than average value potential per prospect means larger number of prospects required for sustainability and growth Opportunity Inventory Undeveloped Land 2.1 million net acres of undeveloped lands Highest in sector relative to size of base assets Unleased fee simple lands with no fixed lessor royalty (~140,000 net acres) Strategic oil sands acreage in northeast Alberta (~322,000 net acres) Active stewardship of undeveloped lands that don t meet risk/reward profile Farmouts, dispositions, share exchange deals, swaps, fee simple land sales 80 70 60 50 40 30 20 10 0 Net Undeveloped Acres/BOE/d 69 20 Peer Group Average (2008) PMT (2008) 25 20 15 10 5 0 6 Net Undeveloped Acres/MBOE Peer Group Average (2008) PMT (2008) 23 Source: CIBC World Markets (4/17/09) Undeveloped land base is three to four times the sector average relative to size
Conventional Shallow Gas Prospect Inventory Cretaceous Mannville and Devonian shallow gas Pool extensions, downspacing for new pools on developed lands and low risk exploration on undeveloped lands 500 + new drill prospects in various stages of technical delineation Multi-zone objectives reduce risk and enhance reserves and economics Seismic definition and step out of infrastructure drive prospects to drill ready Multi-zone drills generally convert to reserves with uphole completions going into prospect inventory Historical drilling success >90% Inventory continually replenished with Crown and freehold land purchases Play Types - Viking offshore bar play - Channel play - Channel trap play - Stratigraphic updip facies change play - Regional sand drape play - Onlap play - Devonian subcrop play Note: Possibility of multiple stacked play types Prospect Inventory Uphole Completions Risked Unrisked Risked Well Resource Resource Capital Zone Count (BCF) (BCF) ($MM) UnConventional Colorado 72 1.6 3.3 14.8 Conventional Viking Equiv 31 2.6 3.5 2.3 UnConventional Viking Equiv 43 16.7 19.6 4.1 Conventional Upper Mannville 393 35.6 51.8 31.8 Conventional Lower Mannville 38 3.9 7.5 2.5 Conventional Other 139 12.6 25.8 14.3 Conventional Total 715 73.0 111.5 69.8 Uphole Completions Add Production for < $10,000 per flowing Boed and Reserves for < $1/Mcf
Conventional Project Economics Northeast Alberta Gas Conventional Shallow Gas - Opportunities Historical Drilling Success Rate Exceeds 90%
Net Asset Value - Risk Discounted (1) December 31, 2008 reserves, less production to September 1, 2009 at Sept 11, 2009 forward strip for 2009 and 2010 per McDaniel July 1, 2009 price forecast thereafter (2) 2009 YTD realized and market-to-market value of PET hedge book at September 11, 2009 (3) Bank debt and convertible debentures at September 11, 2009 net of estimated working capital (4) NAV adjusted to reduce price for remainder of 2009 and 2010 by amount indicated net of hedging effects Net Asset Value - Unrisked (1) December 31, 2008 reserves, less production to September 1, 2009 at Sept 11, 2009 forward strip for 2009 and 2010 per McDaniel July 1, 2009 price forecast thereafter (2) 2009 YTD realized and market-to-market value of PET hedge book at September 11, 2009 (3) Bank debt and convertible debentures at September 11, 2009 net of estimated working capital (4) NAV adjusted to reduce price for remainder of 2009 and 2010 by amount indicated net of hedging effects
Accretive Acquisitions Alberta Sask. Acquisition History Edmonton Athabasca Fort McMurray Trust Spin-out PRL gas assets in NE Alberta 2003 Ells and Epact Exploration 2004 Marten Hills, Cavell, Athabasca & Saleski 2005 NE Alberta 2006 Acquire Co. in East Central Alberta 2007 Craigend/Radway/Stry Birchwavy Acquisition Calgary
Athabasca Acquisition - Value Summary Purchase Price ($MM) Cash Flow / Cap Ex ($MM) Reserves (Bcf) Rolling Reserve Addition Cost ($/BOE) Reserves Acquired (Effective July 1, 2004) 195.7-84.1 $ 13.96 Cumulative Cash Flow to Dec 31/08 (309.0) (64.9) Capital Expenditures to Dec 31/08 42.3 5.7 Net Cost of Reserves at Year End 2008 (71.0) 24.9 $ 0.00 2009E Cash Flow (23.6) (11.2) 2009E Capital Expenditures 3.2 4.9 Net Cost of Reserves at Year End 2009 (91.4) 18.6 $ 0.00 Allocation of hedging gains since acquisition (36.3) Net Cost of Reserves at Year End 2009, with hedging (127.7) 18.6 $ 0.00 2009 Metrics Months to Payout: 40 months (Oct 2007) Estimated Ultimate ROR: 55% ROR with Hedging: 70% Exit 2009 Production: Reserves at End 2009: PV 10% Reserve Value at End 2009: 28.9 MMcf/d 18.6 Bcf (P+P) $42 MM (1) Future value estimates at September 9, 2009 based on forward strip for 2009 and 2010 per McDaniel July 1, 2009 price forecast thereafter Northeast Alberta Value Summary Purchase Price ($MM) Cash Flow / Cap Ex ($MM) Reserves (Bcf) Rolling Reserve Addition Cost ($/BOE) Reserves Acquired (May 17/05) 251.6-70.2 $ 21.50 Cumulative Cash Flow to Dec 31/08 (326.3) (61.1) Capital Expenditures to Dec 31/08 76.5 21.8 Net Cost of Reserves at Year End 2008 1.8 30.9 $ 0.35 2009E Cash Flow (29.9) (10.3) 2009E Capital Expenditures 1.8 3.4 Net Cost of Reserves at Year End 2009 (26.3) 24.0 $ 0.00 Allocation of hedging gains since acquisition (39.9) Net Cost of Reserves at Year End 2009, with hedging (66.2) 24.0 $ 0.00 2009 Metrics Months to Payout: 43 months (Jan 2009) Estimated Ultimate ROR: 24% ROR with Hedging: 36% Exit 2009 Production: Reserves at End 2009: PV10% Reserve Value at End 2009: 23.7 MMcf/d 24.0 Bcf (P+P) $54 MM (1) Future value estimates at September 9, 2009 based on forward strip for 2009 and 2010 per McDaniel July 1, 2009 price forecast thereafter
Birchwavy Acquisition Value Summary Purchase Price ($MM) Cash Flow / Cap Ex ($MM) Reserves (Bcf) Rolling Reserve Addition Cost ($/BOE) Reserves Acquired (June 26/07) 391.8-269.1 $ 8.74 Cumulative Cash Flow to Dec 31/08 (176.2) (35.3) Capital Expenditures to Dec 31/08 49.3 10.1 Net Cost of Reserves at Year End 2008 264.9 243.9 $ 6.52 2009E Cash Flow (36.3) (17.0) 2009E Capital Expenditures 18.5 4.2 Net Cost of Reserves at Year End 2009 247.1 222.7 $6.66 Allocation of hedging gains since acquisition (52.2) Net Cost of Reserves at Year End 2009, with hedging 194.9 222.7 $ 5.25 2009 Metrics Months to Payout: 65 months Exit 2009 Production: 48.2 MMcf/d (Nov 2012) Reserves at End 2009: 222.7 Bcf (P+P) Estimated Ultimate ROR: 55% PV10% Reserve Value ROR with Hedging: 67% at End 2009: $501 MM (1) Future value estimates at September 9, 2009 based on forward strip for 2009 and 2010 per McDaniel July 1, 2009 price forecast thereafter Eastern Alberta Shallow Gas Major Acquisition Potential Ft. McMurray Conventional shallow gas in NE and East Central Alberta may become non-core for major players Synergy with PET s existing asset base allows for facility consolidation and cost savings No incremental G&A required to optimize value Edmonton Encana Conoco Phillips Husky Penn West Harvest Talisman
Conventional Shallow Gas The Hidden Benefits Manageable decline rates Below-average operating costs = good netbacks Cost-effective production and reserve additions Economics are robust - higher rate of return Risks and performance-drivers are well understood by PET Land and property acquisition costs less competitive than resource plays Good flow of M&A product from majors focusing their strategy for higher impact Not service-cost intensive /good availability of services Frac stimulations relatively infrequent Creates solid cash flow for distributions, unconventional gas investment and other new venture growth opportunities For Additional Information: Clay Riddell Executive Chairman Sue Riddell Rose President & CEO Cam Sebastian VP Finance & CFO Sue Showers Investor Relations and Communications Advisor Suite 3200, 605 5 th Avenue SW Calgary, AB T2P 3H5 (403) 269-4400 Fax (403) 269-4444 www.paramountenergy.com Questions? info@paramountenergy.com