Pengrowth December 2010

Corporate Presentation

December, 2010

Advisory

Caution Regarding Forward-Looking Information

This presentation contains forward‐looking statements within the meaning of securities laws, including the "safe harbor" provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward‐looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward‐looking statements in this presentation include, but are not limited to, statements with respect to: benefits and synergies from Pengrowth's corporate and asset acquisitions, business strategy and strengths, goals, focus and the efforts thereof, acquisition criteria, capital expenditures, reserves, reserve life indices, estimated production, production and reserves additions from our development programs, remaining producing reserve lives, net present values of future net revenue from reserves, commodity prices and costs, exchange rates, the impact of contracts for commodities, development plans and programs, tax effect and treatment, future income taxes, taxability of distributions, abandonment and reclamation costs, government royalty rates, expiring acreage and anticipated exploration and development activities. Statements relating to "reserves" involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward‐looking statements and information are based on Pengrowth's current beliefs as well as assumptions made by, and information currently available to, Pengrowth concerning anticipated financial performance, business prospects, strategies, regulatory developments, future oil and natural gas commodity prices and differentials between light, medium and heavy oil prices, future oil and natural gas production levels, future exchange rates, the proceeds of anticipated divestitures, the amount of future cash distributions paid by Pengrowth, the cost of expanding our property holdings, our ability to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and gas successfully to current and new customers, the impact of increasing competition, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through our development and exploration activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. By their very nature, forward‐looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward‐looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward‐looking statements. These factors include, but are not limited to: changes in general economic, market and business conditions; the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth’s ability to replace and expand oil and gas reserves; geological, technical, drilling and processing problems and other difficulties in producing reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; actions by government or regulatory agencies, including changes in tax or royalty laws; the failure to qualify as a mutual fund trust; changes in law or regulations; and Pengrowth’s ability to access external sources of debt and equity capital; and the occurrence of unexpected events involved in the operation and development of oil and gas properties. Further information regarding these factors may be found under the heading "Business Risks" in the management’s discussion and analysis for our most recently completed financial year, under "Risk Factors" in our most recent Annual Information Form on Form 40‐F and in other recent filings with the Securities and Exchange Commission and Canadian securities regulatory authorities.

Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward‐looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward‐looking statements contained in this presentation are made as of the date of this presentation and Pengrowth does not undertake any obligation to up‐date publicly or to revise any of the included forward‐looking statements, whether as a result of new information, future events or otherwise, except as required by law. The forward‐looking statements contained in this presentation are expressly qualified by this cautionary statement..

All figures are in Canadian dollars unless otherwise stated. Production and reserve figures are before royalties.

1. Closing price as at December 6, 2010 2.Includes 5 million exchangeable shares

Corporate Profile

Market Capitalization1

Units Outstanding2

Total Debt

Distribution

Current Yield

$4.3 Billion

325 million

$1.0Billion

$0.07 per unit

6.4%

Production Profile

Average Production1

Year‐to‐date production

Production Mix

Operated Production

Reserves P+P (Dec 31, 2009)

Reserve Life Index

Undeveloped Land

72,704 boe/d

74, 605 boe/d

~ 50% liquids

~ 66%

295.7 mmboe

10.6 Years

860,000 Net Acres

1. Average production as at third quarter 2010

Corporate Strategy

Key Take Aways

• The transition at Pengrowth is well underway

• We have made substantial progress on all fronts• Financial, asset and people

• Delivered on what we promised• The onion has been peeled

• Asset rotation is ongoing

• Lots of opportunity still remains• On our own asset base

• In the acquisition market

• Not all of the way there yet• Moving in the right direction with positive internal momentum

What Have We Been Doing?

• Undertook serious financial surgery and repair• Long‐term debt reduced by $600 mm

• Sustainable business model adopted

• Started asset transition from conventional to unconventional assets

• Identified unconventional opportunities on existing land base

• Asset rotation through acquisitions and dispositions

• Building capacity in the organization• Key personnel in key roles

• Focus organization on fewer larger needle moving projects

• Strengthen technical capabilities

Where are we at?

• Financial• Solid financial footing/foundation• Conversion to dividend paying corporation ready to go• Debt to cash flow still to high• Increased institutional ownership

• Assets• Strong inventory with excellent breadth and depth • Still more layers on the onion to be peeled• Acquisition opportunities are plentiful

• People• Focused on four core areas• All core areas are operated• “nut cracking” core value creation skill set• Technical capabilities are improving at all levels

84%66%106%(Distributions + Capex as a % of cash flow)

1.5x1.4xDebt to EBITDA

$1,037$1,095Total Debt ($Million)3

48%36%44%(Distributions as a % of Cash Flow)

$0.63$0.21$0.21Distributions Declared ($/Unit)

$65.20$68.21$67.35Oil & Liquids ($/Bbl)

$5.05$4.86$4.67Natural Gas ($/Mcf)

$0.48

$143

98%

43/24

$87.68

$1.60

$12.69

72,704

Q3/2010

172/11015/8Wells Drilled (Gross/Net)

$465$170($Millions)

$1.59$0.58($/Unit)

Realized Sales Price(2)

$203.0$51.66Capital Expenditures ($ Million)

99%

$1.68

$12.91

74,605

2010 YTD

100%Success Rate (%)

$1.74Cash G&A ($/Boe)

75,517Production (Boe/d)

Cash Flow(1)

$12.55Production Expenses ($/Boe)

Q2/2010

(1) Before changes in working capital (2) After commodity risk management (3) Including convertible debentures

Operating & Financial Performance

2011 Capital ProgramFocused Capital Program

• $400 million program, a 14% increase from 2010

• Program is designed to be flexible, scalable and responsive to uncertain commodity markets

• 80% of the program is focused on oil and liquids rich gas projects

• 73% of the program is operated

2011 Capital ProgramFocused Capital Program

• Majority of the projects have recycle ratios in excess of two times

• Economic at US$70 WTI and $3.00 AECO

• A portion of the capital program will be funded with selected non‐core dispositions

1.07.1914,250$55Groundbirch

$400

$15

$50

$42

$293

$44

$50

$37

$107

2011

Capital

$million

29,500

29,800

24,100

24,100

28,200

20,700

12 Month

Production Cost(1)

$/boe/d

14.73

16.41

14.13

15.28

16.90

17.27

Add + Promote

Cost(2)

$/boe

Area

Operated

Recycle

Ratio(3)

$/$

Swan Hills 2.0

Olds/Garrington 1.8

Lindbergh

Other 1.9

Operated DCET 1.7

Non‐operated DCET 2.5

Facilities Maintenance

Land, Seismic & Other

Total Capital 1.8

2011 Capital AllocationFocused on Operated Properties

(3) The 2011 net‐back (i.e., 2011 revenue using U.S. $70/bbl WTI, Cdn$3/mcf AECO gas and U.S.$0.95/Cdn$1 minus royalties and operating cost) divided by the Add + Promote Cost

(2) Project capital spent divided by the total production for the life of the project.

(1) Capital spent divided by the quotient of the total of first twelve months production and 365 days.

2011 Guidance

2011 Guidance

Capital Budget $400 Million

Production (Boe/d) 74,000 to 76,000

Operating Costs $13.54 per Boe

General & Administrative $2.69 per Boe

Budget based on US$70/bbl WTI, $3.00/Mcf AECO

Volume/day

Crude oil (bbl per day) 29,000

Natural Gas Liquids (bbl per day) 8,500

Natural gas (mcf per day) 225,000

Total Volume (boe per day) 75,000*

* Assumes mid‐point of guidance

Pengrowth’s Pillars

Inventory Breadth, Depth, Size & TimingFinancial Strength, Flexibility

Value CreationS

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Financial Strategy

Financial StrategyBalance Sheet

• Pengrowth has been focused on debt reduction• Reduced debt by approximately $600 million over past 12 months

• Target debt‐to‐cash flow ratio of between 0.8x and 1.2x and a debt‐to‐capitalizations ratio of < 30%

• Closed U.S. $187 million term notes offering• Pengrowth’s remaining debt averages 6.3% and 7.2 years

• Ample credit capacity available • Renewed $1.0 Billion three year committed term credit facility with $250 million option

• Debt reduction– Over‐finance acquisitions

– Sell assets to increase capital expenditures

• Maintain distributions following conversion

• Hedge to improve cash flow certainty

Financial Strategy2011 Financial Tactics

Hedging Strategy

Provide stability and lock in returns– Capex– Distributions

Current Positions

• Natural Gas– 50,021 mcf/d at CDN $5.72/mcf for 2011

• Crude– 12,000 bbls/d at CDN $87.87/bbl for 2011

– 4,500 bbls/d at CDN $90.92/bbl for 2012

Corporate Conversion

• Special meeting December 16th• Investor appetite for dividends remains high

• Canadian investors tax credit• $2.9B in tax pools indicate 5 years before any new tax is paid

Onion Peeling

Peeling Back Onion Layers of Pengrowth’s Resource Base

“One‐Well Wonders”• Pengrowth’s historical inventory reflected Pengrowth’s old strategy of acquire and exploit

“Peeled back the Onion Layers”• 2010 was a year of creating an inventory of Unconventional Resources

Peeled Back Onion Layers

Identification65

Proof of Concept32

Inventory8

• 65 plays initially identified

• 11 plays dropped

• Currently have 22 plays still in identification phase

• 32 plays have started some POC

• 5 plays dropped

• 18 plays need to finish POC• 10 plays on hold• 8 plays to prove concept

• 8 have had successful POC

Metrics/description of Key Plays

Wells DCET Cost Reserves Typical MetricsLikely Possible Likely Possible Likely Possible Prod Cost Reserve Cost

Play number number $million $million MMboe MMboe $/boe/d $/boe1 Reef Gas Condensate 9 53 $40 $235 3 16 $13,200 $15.202 Reef Oil 5 48 $25 $240 1 8 $30,000 $30.003 Platform Interior 61 126 $260 $550 13 26 $28,900 $21.004 Platform Margin 16 26 $70 $120 4 6 $29,400 $19.50

Swan Hills: 91 253 $395 $1,145 21 56 $24,700 $20.00

5 Montney 91 165 $600 $1,080 75 135 $17,500 $8.006 Doig 20 44 $110 $240 10 25 $20,000 $10.00

Groundbirch: 111 209 $710 $1,320 85 160 $17,900 $8.30

7 Cardium 23 94 $80 $330 3 11 $40,000 $29.008 Viking 47 71 $200 $300 11 17 $30,700 $18.00

Olds/Garrington: 70 165 $280 $630 14 28 $33,900 $21.35

372 1,127 $1,410 $3,225 122 254 $22,699 $12.80

8 POC in three pillar areas

• 2011 Key POC projects• Lindbergh – pilot under development• Polymer• Progress the other 18 POC projects

• Projects with large potential still in portfolio • Horn River Basin• CO2 EOR

Key Proof Of Concept ResultsRR Year Pool Well ID WI 5‐Day Avg. 1 Mo. Avg 3 Mo. Avg 3rd mo avg 12 Mo. Avg

Gross Gross Gross Gross GrossReef Gas Condensate boe/d boe/d boe/d boe/d boe/d

2009 Carson Creek "C" 00/14‐17‐061‐12W5/0 725 580 421 3002009 Carson Creek "C" 02/06‐17‐061‐12W5/0 95% 776 774 607 3832009 Carson Creek "C" 00/13‐19‐061‐12W5/3 95% 981 880 602 4232009 Carson Creek "C" 00/03‐08‐061‐12W5/0 95% 713 728 6012009 Carson Creek "C" 00/12‐18‐061‐12W5/0 95% 585 497 3372009 Carson Creek "C" 00/07‐18‐061‐12W5/0 95% 461 406 4132009 Carson Creek "C" 00/14‐24‐061‐13W5/2 95% 657 448 2542009 Carson Creek "C" 02/01‐08‐061‐12W5/0 95% 329 218 1062009 Carson Creek "C" 00/08‐18‐061‐12W5/0 95% 809 765 5452010 Carson Creek "C" 00/02‐19‐061‐12W5/0 95% 832 4682010 Carson Creek "C" 00/04‐16‐061‐12W5/0 95% 8132010 Carson Creek "C" 00/06‐25‐061‐13W5/2 95% 2142010 Carson Creek "C" 00/12‐20‐061‐12W5/0 95% 2912010 Carson Creek "C" 00/09‐05‐061‐12W5/0 95% 1,2702010 Carson Creek "C" 00/11‐07‐061‐12W5/2 95% 1,1802010 Alexis Pool 100/13‐31‐060‐12W5/0 100% No available results

Average Reef Condensate 767 650 588 432 369Percent Gas 42% 43% 49% 53%

Reef Oil2010 Judy "B" South 02/4‐13‐063‐12W5/0 100% 367

Percent Gas 0%Platform Interior

2010 Carson Ck North 00/15‐02‐062‐12W5/2 89% Frac'd into R5 ‐ wet2010 Judy "A" 00/14‐09‐064‐10W5/0 100% 445 256 201 1732010 Deer Mtn 00/15‐23‐068‐09W5/0 100% 644 362 216 1232010 Deer Mtn 00/08‐23‐068‐09W5/0 100% 239 106 56 242010 House Mtn 00/16‐25‐069‐11W5/0 100% 2542010 House Mtn 00/16‐19‐069‐10W5/0 100% 444

Average Platform Interior 405 241 158 107Percent Gas 0% 0% 0%

Platform MarginDeer Mtn Unit No results 85%

Cardium2010 Olds/Harmattan 14‐14‐32‐3W5 50% 82 402010 Olds/Harmattan 14‐18‐32‐3W5 50% 141 622010 Olds/Harmattan 4‐34‐31‐3W5 60% 265 1682010 Olds/Harmattan 3‐34‐33‐3W5 57% 182 138

Average Cardium 168 102Percent Gas 10%

Viking2010 Olds No results

Key Proof of Concept Wells

5‐Day 1 Mo. Avg 3 Mo. Avg 3rd Mo. Avg 12 Mo. AvgWells Gross Gross Gross Gross Gross

Swan Hills boe/d boe/d % Gas boe/d % Gas boe/d % Gas boe/d % GasReef Gas Condensate 15 767 650 42% 588 43% 432 49% 369 53%

Reef Oil 1 N/A 367 0%Platform Interior 6 405 241 0% 158 0% 107 0%Platform Margin 4 Dril l ing in‐progressTotal Swan Hills 26 586 542 34% 481 39% 350 46% 369 53%

Olds (Cardium / Viking)Cardium 4 168 102 10%Viking Dril l ing & Completions in‐progress

Total Olds 4 168 102 10%

Major ProjectsTremendous Resource Potential

0.5 Bbbl 2.5 tcf

9.5 tcf

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Lindbergh Horn River Groundbirch

OOIP, billion bb

l

0

2

4

6

8

10

DPIIP, tcf

Polymer EORKey Drivers

• OOIP over 1 Billion bbl (gross) – 16 chemical EOR candidates• Chemical EOR potential of 200‐300 MMbbl

• Regionally concentrated opportunities• 8 pools with 70% of OOIP potential in Bodo, Cosine & Cactus Lake• Characterized by two types of reservoir (geology & oil) –McLaren and Lloyd

EOR Estimated Recovery from SurtekRR Polymer AP / ASP

OOIP OOIP P+P Incremental Incremental Incremental Incrementalgross net net RF Recovery RF Recovery

Property mmbbl mmbbl mmbbl percent mmbbl percent mmbbl1 Cactus Lake North McLaren 200 200 0.8 25% 50 35% 702 Bodo Upper Mannvil le B 129 129 0.8 30% 39 42% 543 Bodo Upper Mannvil le T8T 140 93 0.3 24% 22 39% 364 Bodo Upper Mannvil le B 124 124 0.5 24% 30 39% 485 Cactus Lake Non‐Unit 70 70 0.6 36% 25 50% 356 Enchant J & VV 81 81 2.2 24% 19 40% 327 Bodo Upper Mannvil le A 47 47 4.4 38% 18 53% 258 Cosine Lloydminster LK SS 75 75 0.7 10% 8 20% 159 Jenner Upper Mannvil le E 30 30 6.2 15% 5 33% 10

10 Plover Lake 34 34 0.5 7% 2 14% 511 Bodo Upper Mannvil le C 6 6 34% 2 58% 312 Bantry Mannvil le A 123 123 1.0 17% 2113 Bantry Mannvil le D 25 25 17% 414 Oak Cecil B 9 9 0.5 20% 215 Oak Cecil C 8 8 0.5 20% 216 Oak Cecil F 5 5 0.5 20% 1

1,106 1,059 19.6 21% 220 34% 364Highlighted Pools 825 778 9 25% 196 38% 292

• Pilot has confirmed recovery

• Economically ‘Challenged’• CO2 Supply Cost

• Government Take including royalties

Other Potential Pengrowth Fields

• Fenn Big Valley

• Carson Creek

• Deer Mountain

CO2 InjectedAmount, mmcf 1,200Bank size, % 26.2%

RecoveredCO2, % of injected 24%

Incremental Oil, bbl 56,000 2.8% OOIP

Methane, mcf 118,000Ethane, mcf 93,000

Total, boe 92,000‘4.6% OOIP’

Pilot Results

CO2Next Steps and Returns

Gunnel North

Gunnel South

a‐87‐C

b‐37‐Bd‐49‐D

Arc

Apache/Encana

Devon

Nexen

Apache

Husky

Evie Net Pay C.I. 10.0m

Pengrowth

Taqa North

Imperial/Exxon

Imperial/Exxon Loc’ns

2009 & 2010 LOCATIONS

FUTURE LOCATIONS

FUTURE CONTINGENT LOCATIONS

2D Seismic

2010 Results to‐date

• a‐87‐C 50 m Evie cored, will be used for Microseismic

• d‐49‐D successfully drilled

• b‐37‐B new drill: successfully drilled, cored (113 m) Evie

• b‐37‐B vertical completion: 10 day well test = 470 mcfd

• DPIIP: 9.5 TCF

Future Activity

• Drill to earn lands

• Vertical completions to evaluate the land base

Note: 2011 plans deferred to 2012 due to equipment availability issues

Land Base• 30,330 net ha or 113 net sections (136 gross sections)• Gunnel North/South 100% Pengrowth, 10% WI Dilly Creek• Expect majority of lands will be retained for another 10 years

Horn River Development Plan

Onion Peeling

• Refocusing portfolio on unconventional resources• learning curve instead of just learning

• Have identified key resources to develop on our lands• 2011 Four key areas: 85% of budget operated DCET

• Swan Hills = $107 million• Groundbirch = $55 million• Olds (Viking / Cardium) = $37 million• Lindbergh = $50 million

• Inventory• Continue to build through POC expenditures



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Pillar One Swan Hills


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Swan Hills Unit No. 124% WI

Judy Creek BHL Unit100% WI

South Swan Hills Unit9.5% WI

Carson Creek North Unit88.6% WI

House Mountain Unit No. 119.3% WI

Deer MountainUnit No. 185.4% WI

Judy CreekWest BHL Unit

100% WI

Pengrowth Lands

House MountainUnit No.27.1% WI

Deer MountainUnit No. 2

Virginia HillsUnit

Carson Creek Unit95.1% WI

3,122 MMboe

1,105 MMboe

296 MMboe

456 MMboe

1.4 MMboe

578 MMboe

901 MMboe

AB SK

• One of the most significant carbonate oil reservoirs in the WCSB

• The Right Place, with the Right People and the Right Technology

• Known resource with • 5.4 Bln Bbls OOIP (Gross)• 2.3 Bln Bbls net to Pengrowth

• PGF current production 21,000 boe/d

• Utilizing horizontal drilling and multi‐stage acid fracturing technology to exploit low permeability (tight) carbonate reservoir

• 8 proof of concept plays being evaluated

Swan Hills TrendThe Opportunity

Proof of Concept PlaysJudy and Carson Creek

PGF Interests 2010 Proof of Concept Drills

Second WavePekisko Drilling

Activity

BHL “C” Pool

Carson CreekBHL Unit #1

Carson CreekNorth

BHL Unit #1

Judy Creek West

BHL Unit

Judy Creek BHL Unit

BHL “C” Pool

Proof of Concept PlaysDeer and House Mountain

PGF Interests 2010 Proof of Concept Drills

Apache DrillingActivity

Arcan DrillingActivity

Deer MtnUnit #1

Deer MtnNon‐Unit

House MtnNon‐Unit

Swan Hills TrendThe 4 Play types

Platform

PlatformMargin

Reef Reef

Platform Margin•Deer Mtn Unit

Platform Interior•Judy Ck Platform•Carson Ck North•Deer Mtn•House Mtn

Reef Oil•Carson Ck North•Judy Ck South•Judy Creek Interior

Reef Gas Condensate•Carson Ck ‘C’ Pool•Alexis

# Net Sections: 28 42 32 12 114

Total Potential Locations:

36 48 102 24 227

Vert 2008 Drills: 5 2 ‐ ‐ 7

Hz 2009 Drills: 9 ‐ ‐ ‐ 9

Hz 2010 Drills: 8 2 5 4 19

Avg. 1 Month Rate*: 671 (RR09) 367 (RR10) 241 (RR10) ‐ ‐

Avg. 3 Month Rate*: 588 (RR09) ‐ 158 (RR10) ‐ ‐

Avg. 12 Month Rate* 369 (RR09) ‐ ‐ ‐ ‐

5 day Avg IP*: 767 (RR10) ‐ ‐ * boe/d

Hz

Swan Hills TrendThe 4 Play Types

PlatformMargin

Pengrowth Activity

Competitor Activity

Platform MarginPlatform InteriorReef OilReef Gas Condensate

Platform

Reef Reef

Swan Hills Reef Gas Condensate Playe.g. Carson Creek Gas ‐ C Pool

• 14 net sections of land• Liquids rich natural gas• 12 mo. Avg. production =370 boe/d

• 9 wells drilled in 2009• 6 wells drilled in 2010• Potential for up to 20 additional drilling locations

• Play extends south onto PGF/Alexis lands

0

100

200

300

400

500

600

700

0 3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60 63 66

Weeks on Production, Calendar Daily Basis

Tota

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boe

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0

1

2

3

4

5

6

7

8

9

10Wells on Prod

Type Well

Average Hz

Swan Hills Reef Gas Condensate PlayEconomics

2.23.5NPV BT 15 ($MM)

69%>100%ROR

2.262.66Recycle Ratio

$70 WTI/$4 AECO

Oct. GLJ Prices

$15.36F & D ($/boe)

$13,200Cost of Production($/boe/d)

$4.25DCET CapEX Per Well ($MM)

275Gross Reserves Per Well (Mboe)

30%Recovery Factor

150 ‐ 175 bbl/mmcfFluid Properties

2.5‐4.0 OOIP (MMbbl/Sec)

98%Working Interest

Swan Hills Reef Gas Condensate Play•Carson Creek “C” Pool•Alexis

• very high liquid‐rich gas•Very high working interest lands

# of W

ells

Swan Hills Reef Oil Playe.g. Judy Creek Reef Interior

• Legacy light oil play• Concentrated land position• 85 net sections

• Numerous opportunities incl. new drills, re‐entries, recompletions, and workovers

• Historical EOR Operations• Hydrocarbon Miscible Flood

Swan Hills Reef Oil PlayEconomics

Reef

0

50

100

150

200

250

0 12 24 36 48 60 72Month

Prod

uctio

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)

HZ Actual

HZ Type

HZ 3‐stage acid frac

Working Interest 90‐100%

OOIP (MMboe/Sec) 3.0

Fluid Properties 42° API

Recovery Factor 15‐25%

Gross Reserves Per Well (Mboe)

200

DCET CapEX Per Well ($MM)

$3.20

Cost of Production($/boe/d)

$21,400

F & D ($/boe) $16.00

Oct. GLJ Prices

$70 WTI/$4 AECO

Recycle Ratio 4.18 3.56

ROR > 100% 67%

NPV BT 15 ($MM) 2.6 1.7

Swan Hills Reef Oil•Carson Creek North•Judy Creek South•Judy Creek Interior

•41‐44 API light crude oil•Very high working interest lands

Swan Hills Platform Interior Playe.g. House Mountain non‐unit

• At house Mountain, Pengrowth activity off‐setting drilling by Apache

• At Deer Mountain, Pengrowth wells off‐setting Arcan wells

Horizontal Multistage Type CurveDaily Normalized (PD)

0

50

100

150

200

250

300

350

400

450

500

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

c

Prod

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(bbl

/d)

65% COS

DMNU 15‐23

Swan Hills Platform Interior PlayEconomics

Swan Hills Platform Interior•Judy Ck Platform•Carson Ck North•Deer Mtn•House Mtn

•100% working interest lands

Working Interest 100%


Fluid Properties 40°API



195


$4.60


$30,660

F & D ($/boe) $23.50

Oct. GLJ Prices

$70 WTI/$4 AECO


ROR 59% 40%

NPV BT 15 ($MM) 2.97 1.96

Platform Interior Type Curve

Interior Avg. 30 day IP

Months on Production

Swan Hills Platform Margin Playe.g. Deer Mountain Unit #1

•At Deer Mountain, Pengrowth wells off‐setting Arcan wells

•Improved recovery factor due to waterflood EOR

•Higher quality carbonate reservoir (commonly 5‐8% porosity, 10‐20 mD perm)

Swan Hills Platform Margin PlayEconomics

Working Interest 86%


Fluid Properties 40°API



231


$4.50


$29,400

F & D ($/boe) $19.54

Oct. GLJ Prices

$70 WTI/$4 AECO


ROR 54% 43%

NPV BT 15 ($MM) 2.4 1.9

Horizontal Multistage Type CurveDaily Normalized (PD)

0

50

100

150

200

250

300

350

400

450

500

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Months on Prod

Prod

ucin

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(bbl

/d)

Type CurveDM Hz. Frac AVG

Platform Margin Type Curve

HZ. Frac Avg. of 15 wells

Months on Production

Swan Hills Platform Margin•Deer Mountain Unit

•High working interest lands•Attractive economics•Higher recovery factor

Swan Hills Trend Summary

• Pengrowth is the dominant operator in the development of unconventional tight carbonate reservoirs in the Swan Hills Trend

• The Swan Hills Trend is an important core area and makes up 30% of Pengrowth’s total production

• Pengrowth’s net share of the conventional OOIP in this huge carbonate reef fairway is over 2.3 Bln bbls

• With the Right People and the Right Technology, Pengrowth has proven that these assets have significant growth potential and opportunity



Value Creation

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GroundbirchMontney Gas Fairway Competitor Map

• Acquired in July, 2010

• Positions Pengrowth

in one of the most

economic gas plays in

N. America

• Dominated by Majors

Altares

Swan

ParklandMonias

Sunrise

Groundbirch

Kobes

Dry Gas PGF

16

31 36

16

31 36

16

31 36

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F G H E F G H E F G H11 10 9

T77

T78

T79

T80

T81

T82

T77

T78

T79

T80

T81

T82

R21W6R22

R14W6R15R16R17R18R19R20R21R22

Fle:

Oil window

Dawson

Wet Gas

Septimus

• Discovered Petroleum

Initially‐in‐place – Upper Montney 2.46 Tcf

– Doig 0.469 Tcf

• 28 mmcf/d by year

end

• Potential for 56 or 84

mmcf/d through

expansion to 2 or 3

gas plants

Montney Thermal Maturity

Upper Montney StructurePressure/Thickness

DPIIP NET 2.46 Tcf

Monias22 Mpa10 m Upper

Groundbirch37‐40 Mpa140 m Upper

Septimus26 Mpa100 m Upper

Parkland21 Mpa65 m Upper

Dawson26 Mpa

30 m Upper

Swan Lake30 Mpa

40 m Upper20 m Lower

• Over pressured

• Thicker net pay

• Minor liquids and no

water

• Porosity: 4‐7%

>20 Bcf/sec

Doig ShaleLwr Doig Siltstone

Doig Phosphates

Upper Montney

Lower Montney

W EPGF Groundbirch

ShellSunset

ARCParkland

BC AB

Belloy

20 Bcf/sec

125 Bcf/sec

100 Bcf/sec

• Reserves in place

increase to the west

due to thicker pay and

higher pressure

• DPIIP of 125‐130 Bcf per

section (GLJ 2010)

Groundbirch Montney StructureSchematic Cross Section

Groundbirch Value to Pengrowth

• Update: 28 mmcf/d facility on‐stream by December 31, 2010

• 5 Upper Montney wells on production by year end (2 new tests)

• 2011 Activity:

– Drill to Fill ( Complete 5 wells)

– Timing for Plant Expansion (Drill 5 wells and order equipment for Q1 2012 on‐stream)

– Evaluate Doig

• Well Inventory of 168 Montney and 44 Lower Doig and Doig Phosphate wells

• RLI and timing for Montney development

• Take Advantage of New Technology and Commodity prices to maximize value

2011 Horizontal Well

• Avg depth 2600m

• Avg well cost $5.5MM

• Initial Rate 4.2 MMcfd

• Ultimate Recovery 5.0 Bcf

• Initial Royalty 25%

• Avg Royalty 16%

• Avg Opex $1.10/Mcf

Notes:

•Deep gas royalty credit $1MM

•Initial royalty of 25% after royalty credits drawn down

Groundbirch Average Type Curve

0

1

2

3

4

5

1 7 13 19 25 31

Months

Prod

uctio

n R

ate,

MM

cfd

Qi = 4.2 MMcfdEUR = 5 Bcf

Price File $4/Mcf $5/Mcf $6/Mcf GLJ Apr 2010DCF Rate of Return, % BTax 20 33 47 44 ATax 17 26 36 35

Type Curve 5 Bcf

Groundbirch Development Economics

Uncaptured Upside

Potential

Incremental

Reserves

Incremental Recovery Factor

UPPER MONTNEY

Existing 15 well Reserve Booking 101 BCF ~ 4%

Develop to 5 wells per section 405 BCF ~17%

Develop to 8 wells per section 315 BCF ~13%

TOTAL UPPER MONTNEY 821 BCF Total ~34%

DOIG PHOSPHATE

Develop to 2 wells per section (20 wells) 60 BCF ~26%

LOWER DOIG PHOSPHATE

Develop to 2 wells per section (24 wells) 96 BCF ~34%

TOTAL GROUNDBIRCH AREA 977 BCF

Groundbirch Summary

• First facility on‐stream in December 2010, adding 4800 boed to Pengrowth

• Access to large resource with long RLI and 212 potential locations

• Opportunity to add up to 84 mmcf/d of production

• Montney play provides sustainable value creation

• Operating one of the best resource gas plays in North America with huge potential for growth.



Value Creation

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R27W4R28R1W5R2R3R4R5R6

File: None Datum: NAD27 Projection: Stereographic Center: N51.74120 W114.28554 Created in AccuMap™, a product of IHS

Olds/GarringtonCardium/Viking

Viking

Cardium

• Large land base of 44 gross sections

• Two stacked regionally extensive Oil resource plays

• Over 182 MMbbls oil in place (net)‐ Cardium ~ 24 net sections‐ Viking ~ 24 net sections

• Potential for multiple wells per section, per zone (2‐4) that will utilize multistage frac technology

• Ability to lever common drill pads and infrastructure for cost savings and lower OPEX

CompetitorActivity

W E

Lower – Mid Shoreface Bar

ShorewardBasinward

Viking Play

Upper Shoreface & Storm Deposits

Transgressive

Bar/Sheet

W E

Lower Shore

face

Cardium ‐B

Cardium ‐A

Conglomerate

Conglomerate

Shale

Middle Shoreface

~ 25 m

Cardium Play

Olds/GarringtonCardium/Viking Schematics

442010 Drills:

Avg. 12 Month Rate:

‐Avg. 3 Month Rate:

No wells on production100 BoedAvg. 1 Month Rate:

Total Potential Locations:

# Net Sections:

7194

2424

Cardium Viking

Cardium

• Optimizing number of muti‐stage fracs.‐moved from 8 to 15

• Optimizing fluid used for fracs

• 4 wells drilled with 3 on production

0.240.83NPV BT 15 ($MM)

16.6%26.3%ROR

2.02.4Recycle Ratio

$70 WTI/$4 AECO

Oct. GLJ Prices

$29.00F & D ($/boe)




10%Recovery Factor

39⁰ APIFluid Properties

4OOIP (MMbbl/Sec)

55%Working Interest

Olds CardiumType Curve

Cardium Type Curve

Type Curve

Viking

• 1st well being completed with an 8 stage liquid propane frac

• 2 wells currently drilling with 3 rd planned before year end

1.692.73NPV BT 15 ($MM)

28.0%40.0%ROR

3.23.8Recycle Ratio

$70 WTI/$4 AECO

Oct. GLJ Prices

$18.26F & D ($/boe)




15%Recovery Factor

37° APIFluid Properties

3.6OOIP (MMbbl/Sec)

74%Working InterestViking Type Curve

0

50

100

150

200

250

300

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79 82 85

Time (months)

Prod

uctio

n (b

oe/d

)

Type Curve

Olds VikingType Curve

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File: None Datum: NAD27 Projection: Stereographic Center: N51.72937 W114.33672 Created in AccuMap™, a product of IHS

Elkton Subcrop

04-22Test IP: 385

boed Mar 2010

12-02IP: 1000

boed May 2010

16-35RR 2010-

10-20

Apr - 10 May - 10 Aug - 10 Sep - 10 Oct - 10Jun - 10

200

600

400

0

800Total Production (boe/d)NGL Production (boe/d)

04-22-033-03W5 Elkton

16-35 Inline flow test~785 Boe/d

200

600

400

0

800

May - 10 Jun - 10 July - 10 Sep - 10 Oct - 10

Total Production (boe/d)NGL Production (boe/d)

12-02-033-03W5 Elkton

Prod

uctio

n Bo

edPr

oduc

tion

Boed

Olds ElktonHigh deliverable, liquids rich gas

Olds Area

• Stacked reservoirs

• Multiple well potential

• Savings with common drill pads and infrastructure

•Over 182 MMbbls OOIP

•Potential for ~165 net wells



Value Creation

Sw

an H

ills

Gro

undb

irch

Old

s V

ikin

g / C

ardi

umPillar Four Lindbergh

Lind

berg

h

•Potential for 30,000 boe/d

•Estimated OOIP 1.3 Bbbl

•Commercial project would represent 100% of PGF reserve replacement

•Over a 25 year RLI

•Potential doubles if thinner pay zones prove economic

Lindbergh Lease

SAGD Lindbergh

• Revised pilot to 1,200 boe/d

• Assumes two (2) well pairs

• First steam targeted for Q1, 2012

• Phase 2: Develop to 12,000 boe/d

• Phase 3: Expand to 30,000 boe/d

• $50 million capital allocated in

2011 for pilot development

OOIP100 (MMbbl/sec)

Fluid Properties10‐11o API

Reserves per Well Pair1,000 Mboe

Lindbergh Reservoir Characteristics

659.9 2007/07/231AA/16-14-058-05W4/00

18m

Resource Estimation (MM bbl)

No cut‐off 1,491

10 m cut‐off 1,349

15 m cut‐off 608

20 m cut‐off 75

• Anticipated SOR of 3.0

Key Attributes

• Porosity and permeability competitive with other SAGD developments

• Lower viscosity & higher gravity implies good mobility of oil, enhanced recovery and lower diluent costs

• Deeper zone improves thermal efficiency in the reservoir and containment

• All season access and location South of “Fort Mac Hot Bed” anticipated to reduce construction costs

Pilot Status

• Detailed engineering underway

• Completion and warm up design ongoing

• SIR stage with ERCB and AENV

• Stakeholder Consultation to be updated in Q4,

2010 and ongoing in 2011

• Regulatory approval anticipated in Q3, 2011

• First steam anticipated Q1, 2012

30,000 BOE/D Target by 2018

• Phase 1: 1,200 boe/d pilot

• Phase 2: Expand to 12,000 boe/d by 2014

• Phase 3: Expand to 30,000 boe/d by 2018

• Subject to regulatory approvals

• Approximately $1 Billion to invest over 7 years

• The 10 to 15m pay zones could double this

potential to 60,000 boe/d once proven economic

Capital Expenditures

• $50 million: SAGD Pilot

• $350 million: Phase 1, 12,000 boe/d

• $500 million: Phase 3, expand to 30,000 boe/d

• $25 million in seismic and core hole drilling

What’s Different?

• Seasoned SAGD project execution team in place• Meetings with ERCB in October and November, 2010: No major issues identified

• Submission of SIRS anticipated Q1, 2011• Approval anticipated Q3, 2011• Shop fabrication on boilers anticipated December 2010

• Preliminary field work on Source Water line anticipated December 2010

• Observation well and core hole drilling planned for December 2010

Where to from here

• Made significant progress identifying unconventional opportunities on asset base

• Move to develop identified opportunities

• Continue to test proof‐of‐concept plays

• Evaluate acquisition opportunities

• Continue as dividend paying corporation

Pengrowth Energy Trust

Stock Exchange

Toronto: PGF.UNNew York: PGH

Investor Relations

Toll‐free: 1.888.744.1111Email: [email protected]: www.pengrowth.com

Pengrowth Energy Trust

2100, 222 – 3rd Avenue SWCalgary, Alberta, Canada T2P 0B4

Telephone: 403.233.0224Toll Free: 1.800.223.4122Facsimile: 403.265.6251

Pengrowth December 2010

Documents

estimated production

reserve life indices

tax effect

forwar information isoften

taxability of distributions

future income taxes

capital expenditures

development plans