Peter’s and Co. Toronto September 16, 2009 Power to Perform Opportunities in Conventional Gas 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. Forward-Looking Statements
Transcript
Peter’s and Co.Toronto
September 16, 2009
Power to Perform
Opportunities in
Conventional Gas
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.
Forward-Looking Statements
ASSET OPTIMIZATION
ACCRETIVE ACQUISITIONS
HEALTHY BALANCE
SHEETMAXIMIZE
CASH FLOW
MAXIMIZE DISTRIBUTIONS AND UNITHOLDER VALUE
Business Plan
NEW VENTURES
Synergistic To Base Assets• Unconventional Viking and
Colorado Shale• GOB technical solutions• CO2 sequestration & storage• Gas storage• Bitumen land bank• West Holden Mannville CBM
High Impact Growth• Deep Basin exploration
+
CONVENTIONAL SHALLOW GAS
Cash Flow Reinvestment
BASE ASSETS
DISTRIBUTIONS NEW VENTURES
SUSTAINABILITY & DISTRIBUTIONS
GROWTH
CASH FLOW
Cash flow for distribution, reinvestment in shallow gas assets for sustainability and investment in New Ventures for growth
Average annual return on NAV = 28%Value growth per Unit since inception = 166%
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Feb 03 2003 2004 2005 2006 2007 2008
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Cumu
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annu
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urn on
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(%)
Year end net asset value @ 5% Annual distributionsYear end net asset value plus distributions to date Cumulative rate of return on initial NAV (%)
NAV @ Feb 2003 $8.91/Unit
Distributions to Year end 2008 $13.124/UnitNAV @Year end 2008$10.63/Unit
Value Creation - The Model Works
• Current distributions - $0.05 per Unit per month
Operations, Assets and Prospect Inventory
Conventional Shallow Gas
Other Conventional Gas
Unconventional Deep Basin Gas
Unconventional Shallow Gas
Conventional Oil
Bitumen
Edmonton
Athabasca
Fort McMurray
Viking
Grande Prairie
Calgary
Natural Gas Focused Asset Base: 5 Core Producing Areas plus Private Explore Co.
Conventional Shallow Gas - Mannville and DevonianUnconventional Gas - Viking Resource PlayDeep Basin Tight Gas Resource Plays – Rock Creek, Notikewin
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
P+P Reserves(1) 560.7 Bcfe Reserve Life Index (P+P) 8.0 Years
Undeveloped Land Base (Core Producing Areas) 7 Million net acres
E&P New Venture Opportunities:NE Alberta Bitumen Resource Exposure – 330,000 net acres Elmworth Montney – 50,000 net acresMannville CBM
Asset Optimization Strategy Offset annual production through capital investment targeting to maintain production, reserves and opportunities per Unit
PET Operations Profile
2008 Year End P + P Reserves = 560.7 Bcfe Unrisked Additional Reserve Potential = 1,601 Bcfe
Booked reserves represent <60% of the risk-discountedreserve potential and value of PET
Recompletions
Conventional
Unconventional
Oil Sands
Reserve Report
Proved & Probable Undeveloped
Proved & Probable Developed
GOB
New Ventures•Gas Storage•CO2 Sequestration and Storage•Mannville CBM
2008 Year End P + P Reserves = 560.7 Bcfe Risk-Discounted Additional Reserve Potential = 345 Bcfe
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
Source: Peters & Co. (Fall 2008)
Rate of Return Break-Even Gas Price
Great return on investment in $7.00 gas price environment
The Downside – Reserve and value adds per opportunity are relatively small
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 - $350K / well)
Conventional Shallow Gas Investment - How Does it Stack Up?
Source: Peters & Co.
Top Natural Gas Play Types - Western Canada Sedimentary BasinFull Cycle Incremental Well
F&D Cost Break-evenIndex per BOE Rate of NPV 10% NPV/Mcf PriceNo. Play Type Province (C$/BOE) Return (C$MM) (C$/Mcf) (C$/Mcf)
PET - Shallow Gas Alberta $10.27 20% $0.33 $0.78 $4.661 Cardium Alberta $11.43 18% $1.15 $0.86 $4.1216 Montney Horizontal - Kaybob Alberta $11.48 14% $2.39 $0.77 $4.378 Edmonton Sands Alberta $14.80 8% $0.23 $0.81 $4.6710 Generic Gas - Countess/Drumheller Alberta $16.15 5% $0.22 $0.76 $4.8715 Montney Horizontal - Dawson B.C. $11.40 3% $3.11 $0.63 $4.666 Devonian Gas Alberta $7.67 2% $4.90 $0.11 $5.592 CBM - Horseshoe Canyon Alberta $21.83 n/a n/a n/a $6.339 Foothills Halfway B.C. $9.59 n/a $0.42 $0.18 $5.5121 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. (June 2009)
Investment still warranted if long term gas prices average $6.00/Mcf and cost
reduction initiatives persist
East Central Alberta Conventional Shallow Gas – Economics
• 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
• Difficult for investment community to technically verify scope and risk of prospect inventory
• Lacks ‘pizzazz’ for capital markets
Conventional Shallow Gas - Challenges
Smaller than average value potential per prospect means larger number of prospects required for
sustainability and growth
• 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
Opportunity Inventory – Undeveloped Land
Undeveloped land base is three to four times the sector average relative to size
Net Undeveloped Acres/BOE/d
69
20
01020304050607080
Peer Group Average (2008) PMT (2008)
Net Undeveloped Acres/MBOE
6
23
0
5
10
15
20
25
Peer Group Average (2008) PMT (2008)Source: CIBC World Markets
(4/17/09)
• 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
Conventional Shallow Gas Prospect Inventory
Play Types- Viking offshore bar play- Channel play- Channel trap play- Stratigraphic updip
Uphole Completions Add Production for < $10,000 per flowing Boed and Reserves for < $1/Mcf
Conventional Project Economics – Northeast Alberta Gas
Conventional Shallow Gas - Opportunities
Historical Drilling Success Rate Exceeds 90%
(1) December 31, 2008 reserves, less production to September 1, 2009 at Sept 11, 2009 forward strip for 2009 and 2010 per McDaniel July 1, 2009 price forecast thereafter
(2) 2009 YTD realized and market-to-market value of PET hedge book at September 11, 2009(3) Bank debt and convertible debentures at September 11, 2009 net of estimated working capital (4) NAV adjusted to reduce price for remainder of 2009 and 2010 by amount indicated net of hedging effects
Net Asset Value - Risk Discounted
Net Asset Value - Unrisked
(1) December 31, 2008 reserves, less production to September 1, 2009 at Sept 11, 2009 forward strip for 2009 and 2010 per McDaniel July 1, 2009 price forecast thereafter
(2) 2009 YTD realized and market-to-market value of PET hedge book at September 11, 2009(3) Bank debt and convertible debentures at September 11, 2009 net of estimated working capital (4) NAV adjusted to reduce price for remainder of 2009 and 2010 by amount indicated net of hedging effects
Accretive Acquisitions
Trust Spin-outPRL gas assets in NE Alberta
2003Ells and Epact Exploration
2004Marten Hills, Cavell, Athabasca & Saleski
2005NE Alberta
2006Acquire Co. in East Central Alberta
2007Edmonton
Fort McMurray
Athabasca
Calgary
Alberta Sask. Acquisition History
Craigend/Radway/Stry
Birchwavy Acquisition
Athabasca Acquisition - Value SummaryPurchase
Price
($MM)
Cash Flow / Cap Ex
($MM)
Reserves
(Bcf)
Rolling Reserve Addition
Cost($/BOE)
Reserves Acquired (Effective July 1, 2004) 195.7 - 84.1 $ 13.96Cumulative Cash Flow to Dec 31/08 (309.0) (64.9)Capital Expenditures to Dec 31/08 42.3 5.7Net Cost of Reserves at Year End 2008 (71.0) 24.9 $ 0.002009E Cash Flow (23.6) (11.2)2009E Capital Expenditures 3.2 4.9Net Cost of Reserves at Year End 2009 (91.4) 18.6 $ 0.00Allocation of hedging gains since acquisition (36.3)Net Cost of Reserves at Year End 2009, with hedging (127.7) 18.6 $ 0.00
Months to Payout: 40 months(Oct 2007)
Estimated Ultimate ROR: 55%ROR with Hedging: 70%
Exit 2009 Production: 28.9 MMcf/dReserves at End 2009: 18.6 Bcf (P+P)PV 10% Reserve Value
at End 2009: $42 MM
2009 Metrics
(1) Future value estimates at September 9, 2009 based on forward strip for 2009 and 2010 per McDaniel July 1, 2009 price forecast thereafter
Northeast Alberta – Value SummaryPurchase
Price
($MM)
Cash Flow / Cap Ex
($MM)
Reserves
(Bcf)
Rolling Reserve Addition
Cost($/BOE)
Reserves Acquired (May 17/05) 251.6 - 70.2 $ 21.50Cumulative Cash Flow to Dec 31/08 (326.3) (61.1)Capital Expenditures to Dec 31/08 76.5 21.8Net 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 3.4Net Cost of Reserves at Year End 2009 (26.3) 24.0 $ 0.00Allocation of hedging gains since acquisition (39.9)Net Cost of Reserves at Year End 2009, with hedging (66.2) 24.0 $ 0.00
Months to Payout: 43 months(Jan 2009)
Estimated Ultimate ROR: 24%ROR with Hedging: 36%
Exit 2009 Production: 23.7 MMcf/dReserves at End 2009: 24.0 Bcf (P+P)PV10% Reserve Value
at End 2009: $54 MM
2009 Metrics
(1) Future value estimates at September 9, 2009 based on forward strip for 2009 and 2010 per McDaniel July 1, 2009 price forecast thereafter
Birchwavy Acquisition – Value Summary
Purchase Price
($MM)
Cash Flow / Cap Ex
($MM)
Reserves
(Bcf)
Rolling Reserve Addition
Cost($/BOE)
Reserves Acquired (June 26/07) 391.8 - 269.1 $ 8.74Cumulative Cash Flow to Dec 31/08 (176.2) (35.3)Capital Expenditures to Dec 31/08 49.3 10.1Net Cost of Reserves at Year End 2008 264.9 243.9 $ 6.522009E Cash Flow (36.3) (17.0)2009E Capital Expenditures 18.5 4.2Net Cost of Reserves at Year End 2009 247.1 222.7 $6.66Allocation of hedging gains since acquisition (52.2)Net Cost of Reserves at Year End 2009, with hedging 194.9 222.7 $ 5.25
Months to Payout: 65 months(Nov 2012)
Estimated Ultimate ROR: 55%ROR with Hedging: 67%
Exit 2009 Production: 48.2 MMcf/dReserves at End 2009: 222.7 Bcf (P+P)PV10% Reserve Value
at End 2009: $501 MM
2009 Metrics
(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
