Peace River Oil PartnershipSeal Main HCSS Pilot

Scheme Approval No. 11377AAnnual ERCB Progress Presentation

January 19, 2011

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Advisory

General: This presentation is for information purposes only and is not intended to, and should not be construed to constitute, an offer to sell or the solicitation of an offer to buy, securities of Penn West. This presentation and its contents should not be construed, under any circumstances, as investment, tax or legal advice. Any person accepting delivery of this presentation acknowledges the need to conduct their own thorough investigation into Penn West and its activities before considering any investment in its securities. Forward-looking Statement Disclaimer: In the interest of providing investors with information regarding Penn West, including management's assessment of Penn West's future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "potential", "target", "seek", "budget", "predict", "might" and similar words suggesting future events or future performance. All statements other than statements of historical fact may be forward-looking statements. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains, without limitation, forward-looking statements pertaining to the following: total 2010 forecast capital expenditures and production rates; total 2011 forecast capital expenditures and production rates; our business strategies and plans for the remainder of 2010, 2011 and 2012, including our intention to focus on oil development using horizontal multistage technology; our forecast 2010 year end total debt levels; our financial hedging strategies; the proposed allocation of our 2011 capital budget; forecast 2011 production growth, production rates, funds flow, year end debt levels, debt to cash flow ratio, capital efficiency and wells drilled; forecast 2012 metrics; 2011 capital program focus information, including target net present value per well information and target internal rate of return information; forecast 2010 and 2011 activity levels in relation to operated wells; forecast 2010 and 2011 total meters drilled and type of drilling; certain forecast information in respect of our Cardium,Amaranth, Colorado Group, Northern Carbonates and Cordova Embayment properties, including the potential quantity of recoverable resource that we believe exists at each property, the incremental production growth that may result from our 2010 and 2011 drilling programs, the potential volumes of additional reserves per well that may result from initial production rates on wells drilled in these areas, projected production curve information for wells drilled in these areas, forecast information regarding drilling, completing, tie-ins and budgeting for wells drilled on these properties, forecast 2011 development information for these properties (including capital expenditures, finding and development costs, capital efficiencies, internal rates of return, net present value per well, total wells drilled and rig counts), the potential for cost reductions and efficiencies on our Cardium property (including the potential benefits of pad drilling), our estimates of the resource in place and original oil in place volumes at our Amaranth property, and our estimates of original oil in place volumes on our Northern Carbonates property and the potential for development thereon; our estimate of the volume of the resource, our 2010 and 2011 capital expenditure levels and activities of our Peace River oil partnership; our 2010 and 2011 exploration strategy and plans in Western Canada; and the forecast impact of a 10 percent change in certain variables on our forecast 2011 funds flow. With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: our intention to convert from a trust structure to a corporate structure, including the timing thereof and the method of accomplishing such conversion; the laws and regulations that we will be required to comply with, including laws and regulations relating to taxation, royalty regimes and environmental protection; future capital expenditure levels; future oil and natural gas prices and differentials between light, medium and heavy oil prices; future oil and natural gas production levels; future exchange rates and interest rates; future debt levels; the amount of future cash distributions that we intend to pay; 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 natural 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 exploitation activities. In addition, many of the forward-looking statements contained in this document are located proximate to assumptions that are specific to those forward-looking statements, and such assumptions should be taken into account when reading such forward-looking statements. Although we believe that the expectations reflected in the forward-looking statements contained in this presentation, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the impact of weather conditions on seasonal demand and our ability to execute capital programs; risks inherent in oil and natural gas operations; uncertainties associated with estimating reserves and resources; competition for, among other things, capital, acquisitions of reserves, resources, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems; general economic conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of oil and natural gas; royalties payable in respect of our oil and natural gas production and changes thereto; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events that can reduce production or cause production to be shut-in or delayed; failure to obtain industry partner and other third-party consents and approvals when required; stock market volatility and market valuations; OPEC's ability to control production and balance global supply and demand of crude oil at desired price levels; political uncertainty, including the risks of hostilities, in the petroleum producing regions of the world; the need to obtain required approvals from regulatory authorities from time to time; failure to realize the anticipated benefits of acquisitions, including the completed acquisitions discussed herein; changes in taxation laws and regulations that affect us and our security holders; changes in government royalty frameworks in jurisdictions in which we operate and the impact that such changes may have on us; uncertainty of obtaining required approvals in respect of acquisitions and mergers; and the other factors described under "Risk Factors" in our Annual Information Form, and described in our public filings available in Canada at www.sedar.comand in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive. The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement. Oil and Gas Advisories:This presentation refers to “Discovered Petroleum Initially-In-Place”, “DPIIP”, “Original oil-in-place”, “OOIP”, “Resource in Place” and “Resource”. We use these terms interchangeably. “DPIIP” is defined in the Canadian Oil and Gas Evaluation Handbook as that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves and contingent resources; the remainder is unrecoverable. A recovery project cannot be defined for these volumes of DPIIP at this time. There is no certainty that it will be commercially viable to produce any portion of the resources. This presentation refers to “Recoverable Resource”, which we define as the recoverable portion of DPIIP, which includes production, reserves and contingent resources. The remainder of the DPIIP is unrecoverable. This presentation refers to “Reserves” figures based on one month production rates, three month production rates and twelve month production rates in respect of our Cardium, Amaranth, Colorado Group, Northern Carbonates and Cordova Embayment properties. These figures are internal estimates of the potential volumes of additional reserves per well that may result from initial production rates derived from wells drilled in these areas. These potential reserves figures have not been audited or reviewed by an independent third party engineering firm and no assurance can be given that an independent third party engineering firm would agree with our conclusions. See “Forward-looking Statement Disclaimer” above. Where reserves or production are stated on a barrel of oil equivalent (boe) basis, natural gas volumes have been converted to a barrel of oil equivalent (boe) at a ratio of six thousand cubic feet of natural gas to one barrel of oil. This conversion ratio is based upon an energy equivalent conversion method primarily applicable at the burner tip and does not represent value equivalence at the wellhead. Boes may be misleading, particularly if used in isolation. Non-Canadian GAAP Measures: In this presentation, we refer to certain financial measures that are not determined in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). These measures as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore they may not be comparable with calculations of similar measures for other companies or trusts. Please refer to our publicly filed documents, including our most recently filed management's discussion and analysis of financial condition and results of operations, for a discussion of these non-Canadian GAAP measures, including for a reconciliation of "funds flow" to cash flow from operating activities. We believe that, in conjunction with results presented in accordance with Canadian GAAP, these measures assist in providing a more complete understanding of certain aspects of our results of operations and financial performance. You are cautioned, however, that these measures should not be construed as an alternative to measures determined in accordance with Canadian GAAP as an indication of our performance. Currency: All references are to Canadian dollars unless otherwise specified.

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• Introductions

• Background

• Subsurface Review

• Surface Review

Agenda

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• Robert Gillis - Exploitation Engineer

• Dwayne Sparks - Geologist

• Jason Cowle - Completions Engineer

• Vladimir Vikalo - Reservoir Engineer

• Colin MacLeod - Facilities Engineer

Introduction - Presenters

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Background

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Background – Map of ‘Seal Main’

Primary SchemeBoundary

Thermal PilotLocation

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• Primary scheme development began in 2003

• Seal Main area currently contains 47 primary horizontal production wells

• Most wells at 150m spacing with some at 75m spacing

Background – Primary Development History

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• Approval 11377 for a commercial scheme consisting of a single well HCSS pilot was received November 10, 2009

• Minor changes in Q4 2010 resulted in the amended approval 11377A

Background – Thermal Approval

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• Penn West’s Seal Main thermal pilot consists of a single horizontal cyclic steam stimulation (HCSS) well

• Steam will be injected at the heel of the well, with a maximum bottom-hole pressure of 10.5 MPa, which is less than 90% of the reservoir fracture pressure

• Two injection/production cycles will be completed

• Each injection cycle will target a rate of 250m3/d CWE (Cold Water Equivalent) for 45-60 days, followed by 6 months of production

Background – Thermal Technology

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Subsurface Review

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1. Geology

2. Well Design- Drilling and Completions- Well Instrumentation- Artificial Lift

3. Cross Well Seismic

4. Expected Scheme Performance

5. Future Plans

Subsurface - Agenda

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Geology – Bluesky Formation Overview

13-5-82-15W5 Type Log• Series of north/south oriented, stacked

distributary channels that have incised into the surrounding sand dominated tidal flat sediments

• Average depth of 650m TVD

• Thickness up to 23m.

• Fine to med grained litharenite

• Porosities from 24 to 33% (Avg 28%)

• Permeability from 50 to 5500 mD

• So from 40% to 85% (Avg 79%)

• API gravities of 8.7 to 9.8 API at 15.6 C

• Viscosities from 8,300 – 26,000 cSt at 20 C

Bluesky

Gething

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Geology – Thermal Pilot Location

Spacing 75m from primary wells

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Geology – Top Bluesky Structure Map

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Geology – Base Bluesky Structure Map

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Geology – Net Pay Map

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Geology - Structural Cross-section

102/13-05-82-15W5 100/02-08-82-15W5 104/16-05-82-15W5

Wilrich

WilrichMkr

Bluesky

Gething+45mSS Hz Thermal Pilot Well

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Geology - Core Photos

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Geology - Reservoir Properties

946OIP (e3m3)

1.02Formation Volume Factor

21%Water Saturation

25%Porosity

65Area (arces)

18.5Net pay (m)

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Geology - Fracture Pressure

11,900647 (top Bluesky)18.4 kPa/mBluesky

13,600647 (base Wilrich)21.0 kPa/mWilrich shale (caprock)

Frac Pressure (kPa)Depth, TVD (m)Frac Gardient

• Penn West conducted a mini-frac test in Seal Main in 2009

• We determined that the Bluesky has a frac gradient of 18.4 kpa/mand the Wilrich Shale cap rock has a frac gradient of 21.0 kpa/m

• Frac gradients were calculated by using the closure pressure after each mini-frac, the fracture pressures for the Bluesky and the Wilrich are summarized below:

• ERCB granted Penn West a max BH injection pressure of 10.5 MPa

• Penn West is planning to conduct further analysis in Seal Main area including rock mechanical testing in Wilrich and Bluesky as well as geo-mechanical modeling

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Thermal Wellbore Design

• 60.3mm guide string run to the toe of the well

• 44.5mm coil tubing instrumentation line (18 TK’s)

• 114.3mm injection and production string

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Thermal Wellbore Design

• Dual bubble tube system at the heel & toe (automated N2 purge from surface)

• Ability to inject blanket gas down the 244.5mm intermediate casing

• Insert pump will be installed upon production phase

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Instrumentation & Monitoring – Pilot Well

• 17 thermocouples spaced evenly from the heel (ICP approx. 1000 mMD) to the toe (2200mMD)

• 1 thermocouple at assumed pump intake and bubble tube point (800 mMD)

• Thermocouples chosen due to robust design and proven track record

• Automated dual bubble tube N2 system at the heel and toe for accurate pressure data

• Real-time data capture will be commissioned for office staff

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Instrumentation & Monitoring – Obs. Wells

• Lateral spacing approximately 5m from the horizontal wellbore

• Located at heel, midpoint & toe of horizontal

• Cross-well seismic program will be conducted prior to and post start-up

• Real-time pressure and temperature monitoring via fiber optics and single point pressure gauges spaced in the reservoir

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Artificial Lift

• 3.25” insert rod pump to be run upon production phase

• Top hold-down seating assembly with thermal friction seal (Better for sand control & gas production)

• VFD will be installed to control pump speed and efficiently maximize production rates

• 1280-365-240 pumpjack capable of moving 216 m3/d total fluids at 6 SPM with 240” stroke length

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Cross-Well Seismic

• Objective is to image effect of steam using time-lapse velocity tomograms

• A baseline survey will be acquired pre-steam, and a second survey post-steam

Cross-Well Seismic Obs Well

Cross-Well Seismic Profile

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Scheme Performance - Steam Quality

• Target wellhead steam quality is 80%

• Steam transport distance is minimal, therefore it will not impact steam quality

• ERCB approval for downhole injection pressure is 10.5 MPa

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Scheme Performance - Pilot Objectives

• The goal of the pilot is to test the application of HCSS to determine the viability of commercial development in Seal Main

• Key measurables for the pilot include: • Productivity and injectivity• Operating costs• Operating conditions (injection pressures, steam oil ratios

(SOR), water steam ratio (WSR), produced water quality, produced gas rates and qualities)

• Steam rise monitoring from cross well seismic• Effective steam penetration • Determine optimal horizontal length• Repeatability of the facility design for future pilots• Tune the reservoir model by history matching the cycle

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Scheme Performance - Forecasting

• Initially a geological model was created using “Petrel”, the area around the “Pilot Well” was selected to create a simulation model

• Model was tuned by history matching primary production performance for nine existing wells

• Model was used to predict HCSS performance

• First Cycle – 45 Injection Days, 15 Soak Days and 6.5 Months production cycle

• Second Cycle – 60 Injection Days, 15 Soak Days and 8 Months of Production

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Scheme Performance - Simulation Results

CSS Well Behavior

0102030405060708090

100

0 100 200 300 400 500 600 700

Thermal Production Days

Oil

Rat

e [m

3/da

y]

02000400060008000100001200014000160001800020000

Oil

Cum

[m3]

Oil Rate Oil Cum

• Injection Rate will be about 250 m3/d CWE while Cumulative Injection will be about 25,800 m3 CWE

• Cumulative Production after first cycle will be about 8,000 m3 while end production will be close to 18,000 m3

• Estimated CSOR will be about 1.4

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• Design of larger pilot or commercial scale operation to depend on pilot results

• Determine whether HCSS above fracture pressure is a commercially viable technology in Seal Main

• Penn West is also investigating potential thermal projects in other parts of the Peace River Oil Sands

Future Plans

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Surface Review

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1. Facilities

2. Measurement and Reporting

3. Water Source

4. Waste Water Disposal

5. Environmental

6. Compliance Statement

7. Future Plans

Surface - Agenda

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Facilities - Pilot Plot Plan

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Facilities - Simplified Process Flow Diagramat 9-6-82-15 W5

To gas gathering P/L

Gas Cooler

Flare K.O. Flare Stack

Raw Water

Water Filtration / Softening Package

Production Emulsion

Production Emulsion

Production Emulsion

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• Oil production volumes will be estimated on lease by tank gauge and measured at the sales point by coriolis meter

• Gas production will be measured on lease by orifice meters

• Steam injection volumes will be measured by orifice meter

• Water is separated and disposed of at our 13-08-82-15 W5 facility

Measurement and Reporting

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Water Source

• The Peace River Town Council has approved the sale of water to Penn West

• Two cyclic steam phases planned

• Phase One: Inject steam for 45 days, cooling water required for under 30 days, then produce for approximately 6 months

• Water design rates:

• Injection water 45 days x 250 m3/d = 11,250 m3

• Cooling water 30 days x 80 m3/d = 2,400 m3

• Total for phase one 13,650 m3

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• Penn West plans to separate produced water from the emulsion at its battery located at 13-08-082-15W5

• The waste water will be injected into a Penn West disposal well at 02-07-082-15W5

Waste Water Disposal

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• Penn West has received a waiver under the Environmental Protection and Enhancement Act (EPEA) to conduct a short term thermal test

• No environmental issues at this time

Environmental

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• To the best of our knowledge, Penn West Exploration is in compliance with all the requirements and conditions of Commercial Scheme Approval 11377A, and all other approvals related to the Seal Main HCSS Pilot

• The pilot MARP was approved by the ERCB on April 28, 2010, The MARP with minor revisions will be resubmitted to the ERCB now that the design package has been issued for construction

Compliance Statement

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• Future facility requirements largely dependent on pilot results

• Evaluate future uses for pilot facility

• Evaluate water sources and recycle techniques for commercial scale development

Future Plans

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Questions?