Corporate Presentation - Seeking Alpha · 3/28/2016 · Corporate Presentation January 2014 . pennwest.com | TSX ... See “Non-GAAP Measures Advisory”. ... Declared fourth quarter

Corporate Presentation January 2014

2 pennwest.com | TSX: PWT NYSE: PWE

Cautionary Note Regarding Our Long-Term Plan and Related Information

This presentation sets forth information regarding our five year plan (the "Plan") and related operational, financial and other performance targets

(the "Performance Targets") from 2014 to 2018. Our Plan and related Performance Targets are used by our board of directors and senior

management for strategic planning purposes. We are disclosing this information to help investors understand the factors that are currently guiding

our planned and future activities and other decision making. Readers are cautioned that this information may not be appropriate for any

other purpose.

Our Plan and related Performance Targets are not, and should not be construed as, forecasts, budgets, or guidance and should not be

relied upon as (and are not) assurances of future performance. Our board of directors has only approved capital budgets and production

guidance for 2013 and 2014. Budgets and guidance subsequent to 2014 have not been finalized and are subject to a variety of factors

and contingencies, including our operational results and any adjustments that we may make to our Plan and/or the assumptions on which it is

based.

Our Plan and related Performance Targets are based on various assumptions described throughout this presentation, including assumptions

relating to the operational activities that we will undertake and the success thereof, the assets that we will sell, the prices that we will receive for

our products, the exchange rates and interest rates to which we will be subject, the debt levels that we will carry, our production levels and product

mix, our funds flow, the amount of cash taxes that we will pay, the amount of dividends that we will pay, the hedging activities that we will

undertake, and the number of shares that we will have outstanding. See in particular “Long-Term Plan Pricing Assumptions" on page 52. While

we believe that our assumptions are reasonable, no assurance can be given that our assumptions will prove to be correct, and

variances could be material.

Readers should be aware that, as with any business, we expect that we will need to continually adjust our Plan to reflect internal and external

factors, such as our operational results, and to reflect changes to the assumptions on which our Plan and related Performance Targets are based.

When changes are made to our Plan and/or our assumptions, our related Performance Targets will also change.

All information regarding our Plan and related Performance Targets set out herein constitute forward-looking information. Investors should read

all of the advisories located at the end of this presentation, including our "Forward-Looking Information Advisory" beginning on page

58.

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, our securities. This presentation and its contents should not be construed, under any circumstances, as investment,

tax or legal advice. Any person viewing or accepting delivery of this presentation acknowledges the need to conduct their own thorough

investigation into our company, our business and our activities before considering any investment in our securities. Among other things,

investors should review our public filings which are available in Canada at www.sedar.com and in the United States at www.sec.gov.


Corporate Summary

Switchgrass

Big

Hill

Big Hill

Big Hill

Cardium

District

Penn West land position

Listing TSX: PWT NYSE: PWE

Market Capitalization(1) $4.5 billion

Shares Outstanding(4) 490 million

Liquidity(2) TSX: 2.4 million NYSE: 2.4 million

2014 Production Forecast 101 - 106 mboe/d (66% liquids)

2014 Capital Budget $900 million

Average gravity of liquids 32o API(5)

Land Position 4.8 million net acres

Quarterly Dividend $0.14 /share

Cardium District(1)(3) 34.5 mboe/d (57% liquids)

Big Hill(1)(3) 39 mboe/d (83% liquids)

Switchgrass(1)(3) 30 mboe/d (51% liquids)

(1) As at January 20, 2014 (2) Three month avg. daily volume (TSX/NYSE) (3) Combined volumes sum to mid-point of 2014 production guidance (4) As at November 5, 2013 (5) See “Definitions and Industry Terms”

Calgary

Edmonton


Penn West Value Proposition

Focused Portfolio

Target “Best-in-Basin” Operator Status

Reliable Production Performance

Improving Capital Efficiency

Strengthening Balance Sheet

Maximize return to shareholders through efficient

development and production of established light oil resources

See “Forward-Looking Information Advisory”.


Changing to Become Canada’s Leading Conventional Liquids Producer

Target debt to funds flow ratio of 1.0 – 1.5x(1)(3)

Expected annual sustainability ratio of ~110%(1)(3)

Target $1.5 – $2.0B in asset

sales by 2015

Capital program on average

allocates 87% to new

production adds

Operated development capital

program 98% focused on

three key areas

Target best-in-play cost &

recovery metrics

Anticipate >100% development

replacement ratio(2) annually

Target $15 – $20 per boe

operated development capital cost(2)

Cost leader in core plays;

continuous improvement in plan

Target per barrel netbacks (1)

have CAGR(2) of 10.6%

(1) See “Non-GAAP Measures Advisory”. (2) See “Definitions and Industry Terms”. (3) For funds flow, see “Long-Term Plan Pricing Assumptions” and other significant plan assumptions

included in the “Forward-Looking Information Advisory”.


Penn West’s Long-Term Plan Delivers Value Added Liquids Growth & Financial Performance

(1) For funds flow, see “Long-Term Pricing Assumptions” and other significant plan assumptions included in the “Forward-Looking Information Advisory”. (2) See “Forward-Looking

Information Advisory”. (3) See “Non-GAAP Measures Advisory”. (4) See “Definitions and Industry Terms”.

$0

$500

$1,000

$1,500

$2,000

50

100

150

200

2013 2014 2015 2016 2017 2018

An

nu

al

Ave

rag

e P

rod

uc

tio

n(2

)

(mb

oe

)

Fu

nd

s F

low

(1)(

2)(

3)

($M

M)

18.7% CAGR(4)

7.3% CAGR(4)

Penn West’s new strategy provides for stable and growing funds flow


Q3 Financial & Operating Highlights

Funds flow(1) of $293MM ($0.60/share)

- Total debt of $3.0B (total debt to EBITDA ratio of 2.3x)(1)

Quarterly production of 133,712 boe/d(2) (63% liquids)

Declared fourth quarter dividend of $0.14/share to be paid January 15, 2014

2013 Guidance(3)

- Annual average range narrowed to 135,000 – 137,000 boe/d

- Exit range expected to be in the 128,000 – 130,000 boe/d range

- Capital expenditures are forecast to be less than the $900MM previously guided

Funds Flow Bridge Production Bridge

$277

$20

$12

$293

($3)

($1)

($12)

$250

$270

$290

$310

$330

Q2

2013

Net

Rev

en

ue

Op

era

tin

g C

osts

G&

A

Fin

an

cin

g

Restr

uctu

rin

g

Q3

2013

$M

M

Q2

2013 Declin

e

Dis

po

sit

ion

s

Sh

ut-

In

Tu

rnaro

un

ds

& O

pera

tio

ns

Gro

wth

Ad

ds

Pro

du

cti

on

(b

oe/d

)

Q3

2013

140,083

2,754 133,712

(7,912) (232) (763) (218)

125,000

127,000

129,000

131,000

133,000

135,000

137,000

139,000

141,000

(1) See “Non-GAAP Measures Advisory”. (2) See “Oil and Gas Disclosure Advisory”. (3) See “Forward-Looking Information Advisory”.


2014 Capital Budget Focused on Core Oil Resources & Balanced Across All Quarters

Cardium

$269

Slave Pt

$143 Viking

$150 Waskada

$6

Other Dev

$133

Infrastructure /

Major R&M

$152

2014 Capital Allocation(1) ($MM)

Viking

108

Cardium

67

Slave Pt

17 Other Dev

15 Waskada

3

0

20

40

60

80

100

120

Net

Well

s

2014 Net Wells Drilled By Area

Focus of 2014 capital budget is on maximizing

profitability and capital efficiency

Capital budget of $900MM – 67% focused on

development, drilling 210 net wells

$562MM allocated to the three primary plays

and includes water flood development

Expected Q1/14 capital expenditures of

approximately $230MM

Corp / Other

$47

R&M – Repair and Maintenance. See “Forward-Looking Information Advisory”. (1) Capital by

area includes total operated development capital which includes drilling, completion, tie-in,

facilities, EOR, and major infrastructure capital.


Strategic Review Process Penn West’s Long-Term Plan Strongly Supported

What’s Different?

Focused Portfolio

Oil Growth

Cost Control

Capitalization

Cardium, Viking, Slave Point

Focus on highest return projects

Non-core Asset

Rationalization

Focused dispositions

Target debt to funds

flow ratio of 1.0-1.5x(1)

Focusing asset portfolio

on three core areas

Proceeds used to

reduce debt

Drive cost reductions

Operational excellence

Improve long-term capital efficiencies Sustainable Dividend

a go-forward feature

Debt

Reduction

Target oil production CAGR(2) 12.6%

Target funds flow CAGR(2) 18.7%

See “Forward-Looking Information Advisory”. (1) See “Non-GAAP Measures Advisory”. (2) See “Definitions and Industry Terms”. For funds flow, see “Long-Term Pricing Assumptions”

and other significant plan assumptions included in the “Forward-Looking Information Advisory”.


What Will Not Change Penn West Values

Our commitment to the safety of our employees and contractors

Our commitment to protecting our environment

Be a people place – where high performance matters and potential is realized

Have passion about our industry, care for each other and be a team

Being strong and fair partners in our business dealings

Compensation programs aligned to shareholder interests


Prioritized light oil development – target increasing liquids weighting to

~80% by 2018

Target total production CAGR(1) of 7.3%; oil production CAGR(1) of 12.6%

Cardium is the main focus ramping to target of ~$800MM of development capital

per year by 2018

Superior economics of the Viking play captured early in the plan

Slave Point program grows as funds flow grows, targeting ~$450MM of

development capital per year by 2018

2014 a critical transition year: asset sales; restore the balance sheet;

fully ingrain a high performance culture

Long-Term Plan Overview Repositioning Penn West For Success

(1) See “Definitions and Industry Terms”.


Change Leading to Real Growth In The Plan Period

Oil production grows at a 12.6% CAGR(3) target

Netback(2) grows at a 10.6% CAGR (3) target

Translates into a 14.5% funds flow per debt

adjusted share(2) CAGR(3) target

2014 represents balance sheet reset – transition

year

Conservative price deck assumption

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000

130,000

2014 2015 2016 2017 2018

Funds Flow Netback(1)(2)

10.6% CAGR(3)

$20

$25

$30

$35

$40

$45

2014 2015 2016 2017 2018

Funds Flow Per Debt Adjusted Share(1)(2)

14.5% CAGR(3)

$1.40

$1.60

$1.80

$2.00

$2.20

$2.40

$2.60

$2.80

2014 2015 2016 2017 2018

Annual Average Production(1)

$/b

oe

bo

e/d

$/s

hare

Debt adjusted calculation assumes C$12.00/share flat. Any appreciation in the share price would improve all debt adjusted metrics shown. For funds flow, see “Long-Term Pricing

Assumptions” and other significant plan assumptions included in the “Forward-Looking Information Advisory”. (1) See “Forward-Looking Information Advisory”. (2) See “Non-GAAP

Measures Advisory”. (3) See “Definitions and Industry Terms”.


2014 2015 2016 2017 2018

Operated Development Capital Quality Assets + Disciplined Investment Program = Value Added Growth

Total operated development capital target of ~$4.7B over five years

Cardium is the key development play with ~$2.5B invested during the plan period (>50% of total)

- Full EOR integration modeled

Slave Point capital target of ~$1.3B reflects cash availability, not inventory

Viking will receive target of ~$620MM

- Strong economics - short cycle times provide near-term production & cash generation

- Waskada investment to stabilize production, generate cash

Development plan reflects focus and value growth strategy

0

10

20

30

40

50

60

70

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

Op

era

ted

Develo

pm

en

t C

ap

ital

($M

M/y

ear)

Cu

mu

lati

ve D

evelo

pm

en

t P

rod

ucti

on

(mb

oe/d

)

Operated Development Capital / Production(1)(2)

Production volumes are net of anticipated declines. EOR – Enhanced Oil Recovery. (1) See “Forward-Looking Information Advisory”. (2) See “Definitions and Industry Terms”.


Inventory & Internal Rates of Return Solid Full Cycle Economic Return Programs with Multi-Year Running Room

Significant inventory remains beyond long-term plan

Expect incremental inventory from future appraisal at Slave Point, Cardium

and other areas

65-75%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Viking Waskada Slave Point Cardium

IRR

Well

In

ven

tory

40-50%

30-40% 30-35%

IRRs reflect play performance

over the long-term plan,

based on integration of EOR

pilot work. Ranges reflect

pace of EOR infrastructure

investment.

EOR – Enhanced Oil Recovery. IRR – Internal Rate of Return. (1) See “Non-GAAP Measures Advisory”. (2) See “Forward-Looking Information Advisory”.

Internal Rate of Return By Area(1)(2)


Improve Capital Efficiency Focused on Value Added Reserve Metrics

0%

50%

100%

150%

200%

250%

2014 2015 2016 2017 2018

Development Replacement Ratio(1)(2)

$10

$12

$14

$16

$18

$20

Cardium Slave Pt Viking Waskada

Operated Development Cost(3)

Reserv

es R

ep

lacem

en

t R

ati

o

$/b

oe

(1) See “Definitions and Industry Terms”. (2) See “Forward-Looking Information Advisory”. (3) Target average development cost per boe over the first five years of the long-term plan

period.

Focused on increasing long-term recovery of resources at competitive costs to

increase value over near-term production


Focus on the Balance Sheet Reset and Maintain Discipline

Plan anticipates ~$485MM of dispositions closing by end of 2013 and up to a further $1.5B by end of 2014

- Potential that all or part of incremental $1.5B could close in 2014

Future growth and dividends expected to be predominantly funded through funds flow

- Targeting a long-term sustainability ratio of 110% exclusive of dispositions

- Results in improving debt metrics at target levels post closing of dispositions

Free Cash Flow(4) and Sustainability(1)(2)

Sustainability ratio calculated as (capital investment + cash dividends) / funds flow. (1) See “Forward-Looking Information Advisory”. (2) See “Non-GAAP Measures Advisory”. (3) See

“Definitions and Industry Terms”. (4) For free cash flow, see “Long-Term Pricing Assumptions” and other significant plan assumptions included in the “Forward-Looking Information

Advisory”.

115% 114% 110%

105% 100%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

140%

($1,000)

($500)

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

2014 2015 2016 2017 2018

Free cash flow with A&D(2)(3) Sustainability ratio

$M

M

Su

sta

inab

ilit

y R

ati

o


Focus on the Balance Sheet Add Stability; Reduce Risk

Key financial covenant in both credit facility and private notes is 3.0x senior debt / EBITDA

- No debt to capitalization covenant concerns expected through 2018

Post dispositions, Penn West targets a debt / funds flow ratio of 1.0x – 1.5x

- Target is in-line with development focused, dividend paying peers

Senior Debt / EBITDA(1) & Debt / Funds Flow(1)(2)(3)

Senior debt and total debt equal in all years as no subordinated debt is outstanding in any of the years shown.

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

4.0x

2014 2015 2016 2017 2018

Senior debt / EBITDA

Debt / funds flow

Target debt to

funds flow range

Levera

ge R

ati

o

(1) See “Non-GAAP Measures Advisory”. (2) See “Forward-Looking Information Advisory”. (3) For funds flow, see “Long-Term Pricing Assumptions” and other significant plan

assumptions included in the “Forward-Looking Information Advisory”.


Debt Capital Structure

$0.4B Bank(1)

$2.1B Notes(1)

84% US$

9% C$

6% £

1% €

Senior

Debt

Notes

Senior Debt to EBITDA of 2.2 times at December 31, 2013(1)

Credit Syndicate

$3.0 billion capacity

20 banks

Expires June 30, 2016

Private Notes(1)

$2.1 billion private notes

4.5 years remaining

6.1% coupon rate

(1) Preliminary estimates as at December 31, 2013.


Focus the Portfolio: A&D Strategy

Timing Target Proceeds

Phase 1

Initial non-core asset disposition

- Debt repayment

- Focusing asset base

End 2013

Phase 2

Major portfolio repositioning and focus

- Debt repayment

- Focusing asset base

- Capital allocation to Cardium,

Slave Point, Viking, EOR

End 2014

Phase 3

Ongoing non-core asset rotation

Consolidate positions in Cardium, Slave

Point, Viking

Continuous within

long-term plan

$1.5 to $2.0B

A&D – Acquisition and Divestiture. EOR – Enhanced Oil Recovery. See “Forward-Looking Information Advisory”.


Phase 1: Closed December 20th, 2013 Proceeds of $486MM from non-core asset sales producing ~10,800 boe/d

(46% heavy oil, 35%natural gas, and 18% light oil & NGL’s)

Disposed property characteristics:

- Operating costs of ~$23 per boe

- 1,620 currently producing or suspended wellbores divested

- Net operating income multiple of 5.5 times

- No development capital allocated in long-term plan

Phase 2: Executed Purchase & Sale Agreement January 20th, 2014 Expected proceeds of ~$175MM from non-core asset sales producing ~6,700 boe/d

(58% natural gas)

Property characteristics:

- Operating costs of ~$20 per boe

- Approximately 1,800 currently producing or suspended wellbores to be divested

- Accretive net operating income multiple obtained

- No development capital allocated in long-term plan

- Expected close date: March 14th, 2014

Reflecting the impact of these transactions, 2014 production guidance has been

revised to 101,000 – 106,000 boe/d from 105,000 – 110,000 boe/d

Focus the Portfolio: A&D Strategy Early Success Asset Divestitures Improve Penn West’s Portfolio s

A&D – Acquisition and Divestiture. See “Forward-Looking Information Advisory”.


Focus the Portfolio: A&D Strategy Divested Acreage Improves Focus on Core Light Oil Positions

Switchgrass

Big

Hill

Big Hill

Cardium

District

Phase 1: (Dec 20, 2013)

Completed

$486MM; ~10,800 boe/d

Phase 2: (First Transaction)

Expected

$175MM; ~6,700 boe/d

Big

Hill


Penn West land position

Divested acreage

Calgary

Edmonton


Improve Costs & Netbacks: Operating Costs Project Management Approach toward Attacking Costs

Continual labour force analysis & optimization

Electrical power management

Reliability & workover operating philosophy

Chemical program optimization

Maintenance practices & spending awareness

Industry and competitor bench marking

Top 5 Operating Cost Drivers

Labour

13.3%

13.1%

12.6%

Chemicals

6.8%

Other

48.1%

Operations

6.0%

Electrical

Power

Workovers

Un

it O

pera

tin

g C

osts

($/b

oe)

90,000

100,000

110,000

120,000

130,000

140,000

150,000

160,000

$0

$200

$400

$600

$800

$1,000

2014 2015 2016 2017 2018

Avera

ge A

nn

ual

Pro

du

cti

on

(b

oe/d

)

To

tal O

pera

tin

g C

osts

($M

M)

$14

$15

$16

$17

$18

$19

2014 2015 2016 2017 2018

(1) See “Forward-Looking Information Advisory”.

Total Operating Costs / Production(1)

Unit Operating Costs(1)


Improve Costs & Netbacks: Operating Costs Growing the Business in Cost Advantaged / Competitive Areas

New Development Production

2013(1) 2018(1)

Competitor Best

($/boe)

% of Corporate

Production

% of Corporate

Production

Viking 12.53* 3.2 8.0

Cardium(2) 9.50** 4.6 31.8

Slave Point 16.97** 4.0 8.5

Total 11.8 48.3

* Teine Energy 2013 Energy Conference Presentation

** Ziff Energy – oil peer groups combining primary and water flood type operations

Maintenance

$2.43

Power

$2.30

Company

Labour

$2.04

Property

Taxes

$1.10

Other

$7.62

Corporate Unit

Operating Costs(1)

Total Corporate(1)

$17.47/boe

Workovers

$1.98

Company

Labour

$1.12

$0.90

Property

Taxes

$0.71

Power

$0.65

Other

$3.88

Viking Focus Area(1)

$8.93/boe

$1.68

Lease

Rentals

Workovers

$2.46

$2.25

$2.18

$1.80

Other

$4.73

Cardium Focus Area(1)

$14.60/boe

Company

Labour

Power

Workovers

Chemicals

Maintenance

& Repair,

Mechanical

$1.18

$2.56

$1.99

$1.76

Fuel

$1.36

Other

$5.81

Slave Point Focus Area(1)

$15.03/boe

Workovers

Company

Labour

Maintenance & Repair,

Mechanical

Chemicals

$1.55

2014 forecast costs. (1) See “Forward-Looking Information Advisory”. (2) Indicative new development production predominately focused in the Crimson Lake and Lodgepole areas early

in the long-term plan and expected to expand beyond these areas by 2018.


10%

9%

Building

14% Staff

66%

Other

Technology

Improve Costs & Netbacks: G&A Costs Fit for Purpose – Support Solutions for the Business

Top G&A Cost Drivers

Notable levers are head office staff levels and

subleasing of corporate space

Staffing is the largest component 70% of total

gross G&A

Head office head count reduction from peak of

1,153 in September 30, 2012 to 825 at

September 30, 2013

Continued organizational improvement

Continue to pursue sublease opportunities

Un

it N

et

G&

A C

osts

($/b

oe)

90,000

100,000

110,000

120,000

130,000

140,000

150,000

160,000

$50

$70

$90

$110

$130

$150

$170

$190

2014 2015 2016 2017 2018

Net

G&

A C

osts

($M

M)

Avera

ge A

nn

ual

Pro

du

cti

on

(b

oe/d

)

$2.00

$2.50

$3.00

$3.50

$4.00

2014 2015 2016 2017 2018

G&A – General and Administrative. (1) See “Forward-Looking Information Advisory”. (2) See “Non-GAAP Measures Advisory”.

Net G&A Costs / Production(1)(2)

Unit Net G&A Costs(1)(2)


Oil Growth, Cost Control Lead to Improving Netbacks & Funds Flow Growth

Continued improvement in costs per barrel

Field netback expected to increase ~40% to

$45 per boe by 2018 driving growth in funds

flow(1)(2)(3)

Liquids weighting expected to be ~80% of

total production by 2018

PWT 2014E

2015E 2016E

2017E

2018E

$10

$20

$30

$40

$50

$60

$0 $5 $10 $15 $20

Q2 2

013 F

ield

Netb

ack

befo

re H

ed

gin

g (

$/b

oe)

Q2 2013 Operating Costs ($/boe)

PWT 2014E

2015E 2016E

2017E 2018E

0%

20%

40%

60%

80%

100%

$0 $5 $10 $15 $20

Q2 2

013 L

iqu

ids W

eig

hti

ng

(%

)

Q2 2013 Operating Costs ($/boe)

>40% oil weighted production

40-60% balanced production mix

<40% oil weighted production

G&A – General and Administrative. (1) 2014 - 2018 netback based on internal price deck. (2) See “Forward-Looking Information Advisory”. (3) See “Non-GAAP Measures Advisory”.

For funds flow, see “Long-Term Pricing Assumptions” and other significant plan assumptions included in the “Forward-Looking Information Advisory”.


Programs are high quality as evidenced by robust metrics

- Target 0.7 times PIR, 35% IRR with <$17/boe operated development capital costs

Program selection will be further optimized on an economic basis (yielding

improved metrics), congruent with annual budget process

EOR plans have been integrated into the development plans; significant water

flood development planned in the major plays in the long-term plan

Development inventory beyond the long-term plan is expected to grow as resource

development continues

Long-Term Plan Summary Long-Term Plan Robust, Positioned for a Decade of Solid Results

EOR – Enhanced Oil Recovery. PIR – Profit Investment Ratio. IRR – Internal Rate of Return. See “Definitions and Industry Terms”. See “Forward-Looking Information Advisory”.


Focused On Growing Cash Flow Per Share Cash Flow Growth With Concurrent Deleveraging

14.5% CAGR(4)

$1.40

$1.60

$1.80

$2.00

$2.20

$2.40

$2.60

$2.80

2014 2015 2016 2017 2018

$/s

hare

Increasing Cash Flow / Share(2)(3)

Improving Profitability(2)(3)

(1) For funds flow, see “Long-Term Pricing Assumptions” and other significant plan assumptions included in the “Forward-Looking Information Advisory”. (2) See “Forward-Looking

Information Advisory”. (3) See “Non-GAAP Measures Advisory”. (4) See “Definitions and Industry Terms”.

Growing Total Cash Flow(1)(2)(3)

An

nu

al

Av

era

ge P

rod

ucti

on

(2)

(mboe)

Debt / Funds Flow(1)(2)(3)

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

Target Debt to Funds Flow range

Lev

era

ge R

ati

o

2014 2015 2016 2017 2018

$0

$500

$1,000

$1,500

$2,000

50

100

150

200

Fu

nd

s F

low

(1)(

2)(

3)

($M

M)

18.7% CAGR(4)

7.3% CAGR(4)

2013 2015 2016 2017 2018

10.6% CAGR(4)

$20

$25

$30

$35

$40

$45

$/b

oe

2014 2015 2016 2017 2018

50

60

70

80

90

100

12.6% CAGR(4)

Oil

mb

bls

/d Funds Flow

Netback

2014


Penn West Oil Marketing Strategy

Actively Hedge

Hedge WTI

Hedge differentials (Edmonton/WTI)

Control Barrels to Refiners

Direct market to refiners/end users

Selective use of rail

Establish strategic, long term, multi-stream supply arrangements with refineries

Access World Prices

Contracted 35,000 bbls/d of long-term pipe capacity into PADD III in H2/14

Identify and develop access to world markets

Develop Gulf and/or East Coast tidewater opportunities


Oil Pipeline Transportation Infrastructure

Edmonton

Chicago

Cushing

New Orleans

Houston

Keystone

Keystone XL

Flanagan South

Gateway

Express - Platte

Trans Mountain

TCPL Mainline Conversion

Major Export Pipelines*

Source: Industry

Penn West aims to diversify

its oil marketing by levering

its Gulf access in mid-2014

Canada (mmbbls/d)

Production 3.2

Refining Cap 1.9

Upgrader Cap 1.4

Consumption 1.6

Crude Exports 2.3

Crude Imports 0.7

USA (mmbbls/d)

Production 7.8

Refining Cap 17.5

Consumption 18.0

Crude Imports 7.3 - 8.3

* Existing and planned


Hedging Strategy Balanced Financial Management

2013

55,000 bbls/d of crude oil collared at WTI US$92 x US$104

175 mmcf/d of natural gas contracted at an average fixed price of

C$3.43/mcf for the period between Q3-Q4 2013

$85

$90

$95

$100

$105

$110

$115

Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov

2014 collar range includes the impact of swaps.

Nov 1, 2013

Strip Pricing

Collar Range

Swaps

2013 2014

WT

I U

S$ /

bb

l


Hedging Position – Current Balanced Financial Management

Oil: 2013 - 55,000 bbls/d Collars – (US$91.55 x US$104.42/bbl)

H1/2014 - 20,000 bbls/d Swaps - US$93.74/bbl

H1/2014 - 10,000 bbls/d Collars - (US$93.20/bbl x US$101.00/bbl)

Gas: H2/2013 - 175,000 mcf/d Swaps - $3.43/mcf

2014 - 90,000 mcf/d Swaps - $3.90/mcf

2014 - 50,000 mcf/d Collars - ($3.41/mcf x $4.17/mcf)

Power: 2013 - 50 MWh $55.20/MWh

2014 - 80 MWh $58.50/MWh

2015 - 80 MWh $55.59/MWh

2016 - 25 MWh $49.90/MWh

Assets Overview


Cardium Development Profile Gaining Momentum in Canada’s Largest Light Oil Resource

Well

Co

un

t/year

Operated Development

Capital(1)

$M

M/y

ear

Net Production Adds &

Gross Well Count(1)

$0

$200

$400

$600

$800

2014 2015 2016 2017 2018

0

50

100

150

200

250

300

350

2014 2015 2016 2017 2018 C

um

ula

tive D

evelo

pm

en

t P

rod

ucti

on

(m

bo

e/d

)

0

5

10

15

20

25

30

35

40

45



Cardium Trend Long-Term Development Plan

$M

M/y

ea

r

Cardium Capital Program(1)

Cardium Production(1)

Base Production

bo

e/d

R10W5

T50

5 miles

10 kms

J Lease

Lodgepole

Crimson Lake

Pembina

Willesden

Green

Willesden Green

Pembina

Penn West land

PW 2013 well

PW 2014 well

PW long-term well

Unit boundary

T45

T42

R8

0

10,000

20,000

30,000

40,000

50,000

60,000

2014

2015

2016

2017

2018

Cardium Per Well D&C

Cost Performance(1)(2)

$M

M

$0

$200

$400

$600

$800

2014 2015 2016 2017 2018

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

2012 2013 2014 2015 2016 2017 2018

Complete

Drill

D&C – Drill and Complete. (1) See “Forward-Looking Information Advisory”. (2) See “Definitions and Industry Terms”.


Key Attributes(1)(2)(3)

Working Interest (%) 65

Total PIIP (MMboe) 5,748

Total Contingent Resources (MMboe) 657

Booked Reserves (MMboe 2P YE 2012) 153

Expected Ultimate RF (%) 15 – 30

Reserves Per Well (mboe) 164

Current D&C Capex Per Well ($MM) 2.4 – 2.7

Cardium

Strategic Value & Potential(1)(2)(3)

>600,000 net acres

>650 MMboe contingent resource

Dominant infrastructure position

Proven secondary & EOR upside

2014 Program Focus & Status(1)(2)(3)

Expansion of EOR pilot work in core areas

Focused, growing development programs

CARDIUM

Cardium Resource Conversion(1)(2)(3)

Current Book Long-term

Plan

Resource

Potential

Contingent

Resources

Remaining

Resource

(post long-term

development

plan)

P+PUD 0

100

200

300

400

500

600

700

800

900

MM

bo

e

1P

2P

RF – Recovery Factor. D&C – Drill and Complete. EOR – Enhanced Oil Recovery.

(1) See “Oil and Gas Disclosure Advisory”. (2) See “Forward-Looking Information Advisory”. (3) See “Definitions and Industry Terms”.

Incremental

to book


Cardium – Crimson Lake & Unit 6 Long-Term Development Plan

bo

e/d

Months

Crimson Lake Type Curve(1)

$M

M/w

ell

2 miles

4 kms

R8W5

T43

R6

T44

Penn West land

PW drilled

PW 2013 well

PW 2014 well

PW long-term well

PW EOR

Unit boundary

2014 Appraisal wells

2013 Water

Flood pilots

WGU 9

WGU 6

2013 Water

Flood pilots

2014 Development

0

100

200

300

400

500

0 12 24

P10

P50

P90

Penn West

Complete

Const & Drill

2014 Water Flood

conversions

Proving water flood capability

through 2013 pilots

EOR integrated development

strategy

Major facilities capacity in place to

support long-term plan

Crimson Lake Per Well D&C


$0

$1

$2

$3

$4

$5

2012 2014 Long-term

Plan

D&C – Drill and Complete. EOR – Enhanced Oil Recovery. (1) See “Oil and Gas Disclosure Advisory”. (2) See “Forward-Looking Information Advisory”.


2013


Cardium – Lodgepole & PCU 9 Long-Term Development Plan

bo

e/d

Months

Lodgepole Type Curve(1)

$M

M/w

ell

2 miles

4 kms

R10

T47

R9W5

T48

PCU 9

Penn West land

PW drilled

PW 2013 well

PW 2014 well

PW long-term well

Unit boundary

PCU 9 Injection pilot

0

100

200

300

0 12 24

P10

P50

P90

Penn West

Complete

Const & Drill

Primary & selective EOR

development in 2014

Proven Hz well water injection

performance in PCU 9

Leverage off existing major

facilities

Lodgepole Per Well D&C


$0

$1

$2

$3

4



2012 2014 Long-term

Plan

2013


Cardium – J Lease & Easyford Long-Term Development Plan

bo

e/d

J Lease Type Curve(1)

$M

M

2 miles

4 kms

R8W5

T49

T48

T50

R7

NPCU 1

Penn West land

PW drilled

PW 2014 well

PW long-term well

Unit boundary

Easyford

Complete

Const & Drill

Selective appraisal in 2014

Commence field development

in 2015

Leverage of existing vertical

wells for EOR development

J Lease Per Well D&C


$0

$1

$2

$3

$4

Months

P10

P50

P90

0

50

100

150

200

250

300

0 12 24

Penn West



2012 2014 Long-term

Plan

2013


Viking Development Profile WCSB Leading Economic Returns Prioritized

$M

M/y

ear

Cu

mu

lati

ve D

evelo

pm

en

t P

rod

ucti

on

(mb

oe

/d)

Well

Co

un

t/year

0

20

40

60

80

100

120

0

1

2

3

4

5

6

7

8

9

10

2014 2015 2016 2017 2018

$0

$20

$40

$60

$80

$100

$120

$140

$160

2014 2015 2016 2017 2018


Capital(1)


Gross Well Count(1)



Viking Oil Long-Term Development Plan

R23

Penn West land

PW 2013 well

PW 2014 well

PW long-term well

R20W3

T30

T32

2 miles

4 kms

bb

ls/d

Months

Viking Oil Hz Production

Comparison in Greater Dodsland

Viking Production(2)

bo

e/d

Water Flood

Phase 1 2014

Phase 3

2015

Phase 2

2014

Down spacing

0 12 24

0

2,000

4,000

6,000

8,000

10,000

12,000

Base Production

2014

2015

2016

2017

2018

Viking Per Well D&C Cost

Performance(2)(3)

$M

M

Complete

Drill

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

$1.2

2011 2012 2013 H1 2013 H2 2014-2018

Plan

D&C – Drill and Complete. (1) See “Oil and Gas Disclosure Advisory”. (2) See “Forward-Looking Information Advisory”. (3) See “Definitions and Industry Terms”.

0

10

20

30

40

50

60

70

80

90

Penn West H1/13 program (27 wells)

Penn West average (220 wells)

Industry average (1,243 wells)



Working Interest (%) 92


Booked Reserves (MMboe 2P YE 2012) 33

Expected Ultimate RF (%) 10 – 30

Reserves Per Well (mboe) 54

D&C Capex Per Well ($MM) 0.8

Viking

2014 Play Focus & Status(1)(2)(3)

Industry leader for production results

Achieved competitive costs in early Q4 2013

Implement Avon Hills water flood in 2014

Leverage existing infrastructure

Down-spaced development in Dodsland

VIKING

Viking Resource Conversion

(Dodsland area only)(1)(2)(3)

MM

bo

e

1P

2P P+PUD

Prospective

Resources

Current Book Long-term

Plan

Resource

Potential

Contingent

Resources

Remaining

Resource

(post long-term

development

plan)

Incremental

to book

RF – Recovery Factor. D&C – Drill and Complete. (1) See “Oil and Gas Disclosure Advisory”. (2) See “Forward-Looking Information Advisory”. (3) See “Definitions and Industry Terms”.

0

20

40

60

80


Slave Point Development Profile Extensive Light Oil Upside Potential

$M

M/y

ear

Cu

mu

lati

ve D

evelo

pm

en

t P

rod

ucti

on

(mb

oe/d

)

Well

Co

un

t/year

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

2014 2015 2016 2017 2018

0

10

20

30

40

50

60

70

80

0

2

4

6

8

10

12

14

16

2014 2015 2016 2017 2018


Capital(1)


Gross Well Count(1)



Slave Point Long-Term Development Plan

5 miles

5 kms

R7

T90

R10W5

T87

Sawn

Red

Earth

Otter

$M

M

Penn West land

PW 3D seismic

PW 2013 well

PW 2014 well

PW long-term well

PW 2013 water flood pilot

PW 2014 water flood expansion

bo

e/d

Slave Point Production(1)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

Base Production

2014

2015

2016

2017

2018

Sawn Lake Per Well D&C Cost

Performance(1)(2)

$M

M/y

ea

r

Slave Point Capital Program(1)

Red Earth

Sawn

Otter

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

2014 2015 2016 2017 2018

$0.0

$2.0

$4.0

$6.0

$8.0

2012 2013 2014

Complete

Drill

D&C – Drill and Complete. (1) See “Forward-Looking Information Advisory”. (2) See “Definitions and Industry Terms”.



Working Interest (%) >95

Total PIIP (MMboe) 2,065


Booked Reserves (Mmboe 2P YE 2012) 39

Expected Ultimate RF(1) (%) 14 – 26

Reserves Per Well (mboe) 185 – 300

D&C Capex Per Well ($MM)

Sawn 5.1

Otter 4.1

Red Earth 4.8

Slave Point

SLAVE POINT

2014 Play Focus and Status(1)(2)(3)

Low-Risk development drilling

- Otter – 7 wells

- Sawn – 9 wells

- Red Earth – 2 wells

Otter four long-reach wells

Sawn one step-out test well & 3D seismic

Water flood expansion in Otter

Water flood pilot in Sawn

Red Earth wells validate inventory

Slave Point Resource Conversion(1)(2)(3)

Primary & Secondary Recovery

0

50

100

150

200

250

300

350

400

450

MM

bo

e

1P 2P

P+PUD

Prospective

Resources

Current

Book

Long-term

Plan

Resource

Potential

Contingent

Resources

Remaining

Resource

(post long-term

development

plan)

Incremental

to book



Slave Point – Sawn Long-Term Development Plan

Sawn Type Curve(1)

bo

e/d

Months

Sawn type curve

Penn West average

Industry average

Water Flood pilot

Penn West land

PW drilled

PW 2013 well

PW 2014 well

PW long-term well


3D seismic

T91

R13W5

2 miles

3 kms

0

100

200

300

400

0 6 12 18 24 30

Higher production rates from reef

dominated facies compared to Otter &

competitors

20% cost reduction for D&C since 2012

3D seismic & step-out well evaluates

100% Penn West lands to west.

Expecting stronger response from EOR

pilot in reef facies $

MM

Sawn Lake Per Well D&C


$0.0

$2.0

$4.0

$6.0

$8.0

2012 2013 2014

Complete

Drill

D&C – Drill and Complete. EOR – Enhanced Oil Recovery. (1) See “Oil and Gas Disclosure Advisory”.

(2) See “Forward-Looking Information Advisory”. (3) See “Definitions and Industry Terms”.


2013 wells exceeding expectations

2014 Development drilling

- 7 low risk development wells

- 4 long reach wells will improve

economics of platform facies

Expanding water flood area

- 7 injectors conversions

- Sharing infrastructure cost with

competitor

Slave Point – Otter Long-Term Development Plan

bo

e/d

Months

Otter Type Curve(1)

Otter Wells Exceeding

Budgeted Volumes(2)(3)

Cu

mu

lati

ve

mb

oe

T88

R10W5

2 miles

3 kms

Water Flood

pilot

Water Flood

expansion

Penn West land

PW drilled

PW 2013 well

PW long-term well


PW 2014 water flood expansion

0

50

100

150

200

250

0 12 24

Months

Total Budget

Total Actual



0

50

100

150

200

250

300

1 2 3 4 5 6 7


Slave Point – Red Earth Long-Term Development Plan

bo

e/d

Months

T87

R8W5

2 miles

3 kms

Penn West land

PW drilled

PW 2014 well

PW long-term well

0

100

200

300

0 12 24

Red Earth Type Curve(1)

Red Earth is an under-developed reef

facies analogous to Sawn

2 appraisal drills expected to un-lock

80 Tier 1 locations

Evaluating infrastructure solutions to

support full development scenario



Waskada Development Profile Five Year Summary

$M

M/y

ear

2014 2015 2016 2017 2018 C

um

ula

tive D

evelo

pm

en

t P

rod

ucti

on

(mb

oe/d

)

Well

Co

un

t/year

0

10

20

30

40

50

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

$0

$20

$40

$60

$80

2014 2015 2016 2017 2018


Capital(1)


Gross Well Count(1)



0

10

20

30

40

50

60

70

80

90

100

110

0 12 24

Waskada Free Cash Flow Generation from Light Oil Development

Base Production

bo

e/d

Waskada Type Curve(1)

Waskada Production(2)

0

1,000

2,000

3,000

4,000

5,000

6,000

2014

2015 2016

2017

T1

R24W1

2 miles

3 kms

R26

Penn West land

PW drilled

PW 2013 well

PW 2014 well

PW long-term well

$M

M

Waskada Per Well D&C


Complete

Drill

bo

e/d

Months

Penn West

Penn West average

Industry average

$0.0

$0.4

$0.8

$1.2

$1.6

2012 2013 2014 D&C – Drill and Complete. EOR – Enhanced Oil Recovery. (1) See “Oil and Gas Disclosure Advisory”.



Waskada Resource Conversion(1)(2)(3)

mb

oe

1P

2P

Prospective

Resources

Current

Book

Long-term

Plan

Resource

Potential

Contingent

Resources

Remaining

Resource

(post long-term

development

plan)

0

20

40

60

80

100

120

140

160

180

Remaining

P+PUD


Working Interest (%) 90 – 95

Total PIIP (MMboe) 877

Total Contingent Resource (MMboe) 114

Booked Reserves, mmboe (2P) 31.5

Expected Ultimate RF(1) (%) 4 – 5

D&C Capex Per Well ($MM) 1.65

Waskada

Strategic Value & Potential(1)(2)(3)

Cost structure improvement potential

Oil infrastructure and gas plant in place

Large Tier 1 inventory ~200 wells

Increase recovery from current ~ 2% thru EOR

2014 Play Focus & Status(1)(2)(3)

Targeting cost reduction similar to Viking results

Drill 3 wells to maintain land position

Q4 – Pilot water flood


LOWER

AMARANTH

Supplemental Information


Long-Term Plan Pricing Assumptions

Maintain the $0.14 quarterly dividend through the plan period

Conservative Canadian light oil price assumption of an average of ~$89/bbl

No cash taxes in plan period



Change Budget Change

WTI Oil (US$/bbl)

Funds Flow Impact (C$MM)

- $10.00

- $123 $92.50

+ $10.00

+ $135

Light Differential (US$/bbl)


- $10.00

- $195 - $5.55

+ $10.00

+ $193

AECO Gas (C$/mcf)


- $0.50

- $12 $3.61

+ $0.50

+ $16

FX (C$/US$)


- $0.05

- $81 $1.03

+ $0.05

+ $81

2014 Budget Funds Flow Sensitivities


Long-Term Plan Target Statistics

Target Four Year CAGR (%)

2015 – 2018(1)

Target Five Year CAGR (%)

2014 – 2018(1)

Total Production

boe/d 7.3 2.0

boe/share 6.3 1.1

boe/share (debt adjusted)(3) 4.8 4.0

Oil Production

bbls/d 12.6 8.4

bbls/share 11.5 7.4

bbls/share (debt adjusted)(3) 9.9 10.6

Funds Flow(2)(3)

$MM 18.7 16.3

Funds flow/share 17.6 15.2

Funds flow/share (debt adjusted)(3) 14.5 15.9

Operating Costs

$/boe (3.0) (2.7)

Debt

Senior Debt / EBITDA(3) (13.3) (21.3)

Debt / Funds Flow(3) (9.9) (21.1)

Debt adjusted calculation assumes C$12.00/share flat. Any appreciation in the share price would improve all debt adjusted metrics shown. (1) See “Forward-Looking Information

Advisory”. (2) For funds flow, see “Long-Term Pricing Assumptions” and other significant plan assumptions included in the “Forward-Looking Information Advisory”. (3) See “Non-GAAP

Measures Advisory”.


Funds Flow & Sustainability WTI Sensitivity

Penn West’s internal price deck is consistent with Canadian Bank average

Funds Flow(1)(2) Sustainability Ratio(1)(2)

80%

90%

100%

110%

120%

130%

140%

2014 2015 2016 2017 2018

Internal deck

Canadian Bank average

Bloomberg consensus

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

2014 2015 2016 2017 2018

Internal deck

Canadian Bank average

Bloomberg consensus

$M

M

Su

sta

inab

ilit

y R

ati

o

Sustainability ratio calculated as (capital investment + cash dividends) / funds flow. (1) For funds flow, see “Long-Term Pricing Assumptions” and other significant plan assumptions

included in the “Forward-Looking Information Advisory” and “Internal deck”, “Canadian Bank average” and “Bloomberg consensus” data. (2) See “Forward-Looking Information Advisory”.


2012 Reserves Highlights

Liquids account for over 71% of 2P

Replaced approximately 190%(2)

of 2012

production and achieved overall 2P reserve

growth of 7%(3)

2P F&D(4)

of $25.50 improved ~5% YoY

NPV(5) of reserves is $9.1 billion

(1) Working interest reserves are before royalty burdens and exclude royalty interests.

(2) Excluding economic revisions and acquisitions and disposition activity.

(3) Excluding economic factors and A&D effects.

(4) Industry future development capital.

(5) BT NPV10 of reserves book.

52%

13%

29%

6

Light & Medium Oil

Conventional Heavy Oil

Natural Gas

NGLs

Commodity (2P)

Proved(1)

: 445 mmboe

Proved + Probable (2P)(1)

: 676 mmboe

Proved Producing

Proved Undeveloped

Probable

Reserve Category (% of 2P)

50%

16%

34%


Contingent Resources Major Light Oil Plays

Best Estimate of Resources(1)(2) (mboe)

Resource Class Cardium(3) Slave Point Viking Waskada

Cumulative Production(4) 865,059 30,123 124,166 17,648

Proved plus Probable Reserves(4) 142,662 30,524 31,577 30,073

Total Commercial 1,007,721 60,647 155,743 47,721

Total Oil Contingent 532,889 110,391 101,518 108,093

Total Gas Contingent 123,771 3,717 69,343 5,711

Total Contingent Resources(5)(6) 656,660 114,210 170,997 114,078

Unrecoverable(6)(7) 3,750,151 643,273 798,623 667,679

Total Discovered PIIP(6)(8)(9) 5,414,531 818,130 1,125,364 829,478

Total Oil Prospective 49,178 244,551 15,159 8,411

Total Gas Prospective 23,864 8,244 24,457 494

Total Prospective Resource(10) 73,042 252,736 39,627 8,886

Unrecoverable(7)(10) 260,089 994,334 221,167 37,134

Total Undiscovered PIIP(8)(9)(10) 333,131 1,247,070 260,794 46,021

(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) See footnotes on next page.


Oil and Gas Disclosures Advisory Resource Disclosures

(1) The resource estimates presented herein were prepared by Deloitte LLP ("Deloitte"), an independent qualified reserves evaluator in accordance with the definitions, standards

and procedures contained in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") and National Instrument 51-101 - Standards of Disclosure for Oil and Gas

Activities ("NI 51-101") and are effective as of March 31, 2013. For details of the risks and level of uncertainty associated with recovery of resources as well as the significant

positive and negative factors relevant to the estimates please see our August 7, 2013 press release entitled "Penn West Exploration Announces Results of Contingent Resources

Studies", which is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

(2) All estimates of resources and Reserves in the table represent the best estimate (or in the case of reserves, the Proved plus Probable Reserves) of company gross interests (total

company interest before deductions and excluding royalty interests). The best estimate is considered to be the best estimate of the quantity of resources that will actually be

recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a

50% probability that the quantities actually recovered will equal or exceed the best estimate. The Total Discovered PIIP and Total Undiscovered PIIP estimates include

Unrecoverable volumes and are not an estimate of the substances that will ultimately be recovered.

(3) The Cardium summary is an arithmetic aggregation of individual probabilistic resource studies mechanically updated effective March 31, 2013 for the Alder Flats, Willesden Green

and Pembina areas.

(4) The cumulative production numbers are as of March 31, 2013. The Proved plus Probable Reserves numbers are as at December 31, 2012, adjusted for estimated production

from December 31, 2012 to March 31, 2013, as evaluated and/or audited by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited; for further information regarding the

previously reported Reserves numbers, see Appendix A to our Annual Information Form dated March 13, 2013. From December 31, 2012 to March 31, 2013, total cumulative

production from the properties identified in the table was approximately 3,999 mboe. Deloitte did not conduct an evaluation and/or audit of our reserves in the resource reports.

(5) The economic viability of our Contingent Resources as estimated in the above table is undetermined, as economic studies have not yet been completed. For details of the specific

contingencies that prevent our Contingent Resources from being classified as Reserves please see our August 7, 2013 press release entitled "Penn West Exploration Announces

Results of Contingent Resources Studies", which is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

(6) There is no certainty that it will be commercially viable to produce any portion of these resources.

(7) The Total Discovered PIIP and Total Undiscovered PIIP estimates include Unrecoverable volumes and are not an estimate of the volume of the substances that will ultimately be

recovered.

(8) The Total Discovered PIIP and Total Undiscovered PIIP estimates may not equal the arithmetic sum of the subcategories of the resources because statistical principles indicate

that an arithmetic sum of probabilistically aggregated volumes may be misleading as to the volumes that may actually be recovered. In addition, the reader should note that the

estimates of reserves and resources for individual properties may not reflect the same confidence level as estimates of reserves and resources for all properties, due to the effects

of aggregation.

(9) A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never

be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

(10) There is no certainty that any portion of these resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the

resources.


Oil and Gas Disclosures Advisory Resource Definitions

"Contingent Resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or

technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such

as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered

recoverable quantities associated with a project in the early evaluation stage.

"Discovered Petroleum Initially-In-Place" ("Discovered PIIP") (equivalent to “discovered resources”) is 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 discovered petroleum initially-in-place includes production, reserves, and contingent resources; the

remainder is unrecoverable.

"Cumulative Production" is the cumulative quantity of petroleum that has been recovered at a given date.

"Prospective Resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future

development projects. Prospective resources have both an associated chance of discovery and a chance of development.

"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on

the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being

reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be subclassified based on development and production status.

"Proved Reserves" are those Reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed

the estimated proved reserves. "Probable Reserves" are those additional Reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual

remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable Reserves.

"Total Petroleum Initially-In-Place" ("Total PIIP") (equivalent to “total resources”) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations.

It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in

accumulations yet to be discovered.

"Undiscovered Petroleum Initially-In-Place" ("Undiscovered PIIP") (equivalent to “undiscovered resources”) is that quantity of petroleum that is estimated, on a given date, to be

contained in accumulations yet to be discovered. The recoverable portion of Undiscovered PIIP is referred to as Prospective Resources; the remainder is Unrecoverable.

"Unrecoverable" is that portion of Discovered PIIP or Undiscovered PIIP which is estimated, as of a given date, not to be recoverable by future development projects. A portion of

these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered

due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

Barrels of Oil Equivalent

Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based

on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on

the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is

misleading as an indication of value.


Oil and Gas Disclosures Advisory Reserves Disclosures

The "Booked Reserves" figures disclosed herein are our proved plus probable reserves numbers as at December 31, 2012, as evaluated and/or audited by GLJ Petroleum

Consultants Ltd. and Sproule Associates Limited in reports prepared by them (the "Reserve Reports"). The estimates of reserves for individual properties may not reflect the same

confidence level as estimates of reserves for all properties, due to the effects of aggregation. For further information regarding our reserves, see Appendix A to our Annual

Information Form dated March 13, 2013. The "Reserves per Well" figures disclosed herein are derived from the Reserve Reports. Development replacement ratio figures and

Cardium, Viking (Dodsland area), and Slave Point (primary and secondary recovery) resource conversion figures (or "incremental to book" reserve figures), in each case during our

five year plan period, are not (and should not be construed as) estimates of existing or future reserves.

Type Curves

The production type curves disclosed in this presentation are for illustrative purposes only to demonstrate potential future performance and do not constitute a guarantee of future

well performance in the areas which they describe. The production type curves used in this presentation are constructed from well data representing only those wells deemed to be

most indicative of the go-forward wells that we intend to develop. A "Tier 1 Type Curve" is the expected performance of wells drilled in the core areas of our plays. Future year

inventory may deviate from this type curve as development extends beyond these core areas.

Expected Ultimate Recovery (“EUR”)

In this presentation the expected ultimate recovery factors in various areas do not represent an estimate of resources or reserves but have been provided to show management's

assumptions used for its internal projections and plans. Such information is based on production information from other Penn West wells in the areas as well as the wells of other

industry participants in the areas. EURs were estimated by [Deloitte in connection with its evaluation of the Contingent Resources in our Cardium, Viking and Slave Point areas.]

See "Resource Disclosures".

Production, Reserves and Resource Volumes

The use of the word "gross" in this presentation (i) in relation to our interest in production, reserves or resources, means our working interest (operating or non-operating) share

before deduction of royalties and without including our royalty interests, (ii) in relation to wells, means the total number of wells in which we have an interest, and (iii) in relation to

properties, means the total area of properties in which we have an interest. The use of the word "net" in this presentation (i) in relation to our interest in production, reserves or

resources, means our working interest (operating or non-operating) share after deduction of royalty obligations, plus our royalty interests, (ii) in relation to our interest in wells,

means the number of wells obtained by aggregating our working interest in each of our gross wells, and (iii) in relation to our interest in a property, means the total area in which we

have an interest multiplied by the working interest owned by us. Unless otherwise stated, production volumes and reserves and resource estimates in this presentation are stated on

a gross basis.


Definitions and Industry Terms

All references to dollar amounts in this presentation are to Canadian dollars unless otherwise specified.

A&D means oil and natural gas property acquisitions and divestitures.

API means, in relation to the average gravity of liquids, the American Petroleum Institute measure of the relative density of a petroleum liquid.

Boe / share and Boe / share (debt adjusted) is the amount of total annual production divided by the amount of common shares outstanding. Debt adjusted

common shares outstanding are equalized at $12 per share for outstanding debt.

CAGR means compound annual growth rate. CAGR is calculated determining an average annual rate of growth over a period of time. For the purposes of this

presentation, except where otherwise noted, CAGR figures are calculated from 2015 to 2018. For a summary of CAGRs targeted in the Long-Term Plan, please

refer to page 54.

Capex means capital expenditures.

D&C means drilling and completion capital expenditures.

Development Replacement Ratio is forecast annual Reserves Developed divided by forecast annual production.

EOR means enhanced oil recovery primarily consisting of water flood programs in the Long-Term Plan.

G&A means general and administrative expenses.

IRR means internal rate of return or the discount rate at which the present value of the funds flow from a project including its related capital expenditures equals

zero.

Major R&M means the amount of capital expenditure to improve an existing production facility to a condition superior to its original specifications or the extend its

useful life.

Operated Development Capital includes all direct costs related to our operated development programs including drilling, completions, tie-in, facilities and major

infrastructure capital and excludes production infrastructure/major R&M capital

Operated Development Cost (per boe) is an internal measure used to assess our capital efficiency of converting resources into reserves and undeveloped

reserves into developed reserves. It is calculated as Operated Development Capital divided by Reserves Developed.

P+PUD means the amount of undeveloped reserves included in the Company’s reserves at December 31, 2012 expected to be developed over the first five

years of the Long-Term Plan from operated development programs.

PIR means profit investment ratio or the present value of fund flows from a project divided by the present value of its related capital expenditures.

Reserves Developed is the sum of new reserve additions and reserves converted from undeveloped reserves to developed reserves from targeted operated

development programs.

Working Capital Deficit means the forecast amount of current liabilities in excess of the forecast amount of current assets excluding risk management and

deferred income taxes.


Non-Canadian GAAP Measures Advisory

In this presentation, we refer to certain financial measures that are not determined in accordance with International Financial Reporting Standards ("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. 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. These measures include the following.

Debt to funds flow ratio is Total Debt divided by Funds Flow for a trailing period and is used by us to assess the appropriateness of our debt levels.

Free Cash Flow is Funds Flow less capital expenditures for a property or group of properties and is Funds Flow less capital expenditures and cash dividends when expressed for

the company as whole. We use this measure to monitor the effect of capital and dividend programs on our debt levels.

Free Cash Flow with A&D is Funds Flow less applicable capital expenditures, cash dividends and net cash on acquisition and disposition activities and is used by us to monitor the

effect of capital programs and our A&D activity on our balance sheet.

Funds flow is cash flow from operating activities before changes in non-cash working capital and decommissioning expenditures. Funds flow is used to assess our ability to fund

dividends and planned capital programs. For additional information relating to funds flow, including a reconciliation of our funds flow to our cash flow from operating activities, see

our latest management's discussion and analysis which is available in Canada at www.sedar.com and in the United States at www.sec.gov.

Funds flow netback is the per production amount of funds flow and is used to assess cash profitability of production.

Funds flow per debt adjusted share or Funds flow / share (debt adjusted) is Funds Flow divided by average outstanding common shares or the amount of common shares

outstanding equalized at $12 per share for the amount of outstanding debt and is used by us as a performance measure and to assess our ability to pay dividends.

Net G&A Costs is General and Administrative costs less the amounts operating and capital recovery amounts from joint venture activities and is used by us to assess the

appropriateness of our level of administrative burdens.

Netback and field netback are each a per-unit-of-production measure of operating margin used in capital allocation decisions to economically rank projects, and is the per unit of

production amount of revenue less royalties, operating costs, transportation and realized risk management gains and losses. For additional information relating to netbacks,

including a detailed calculation of our netbacks, see our latest management's discussion and analysis which is available in Canada at www.sedar.com and in the United States at

www.sec.gov.

Senior Debt to EBITDA ratio is the amount senior debt divided by earnings before interest, taxes, depletion, depreciation and amortization and is used by us to assess our

compliance under credit agreements.

Sustainability ratio is a comparison of a company’s cash outflows (capital investment and dividends) to its cash inflows (funds flow) and is used by us to assess the

appropriateness of our dividend levels and our long-term ability to fund our development plans.

Total debt to EBITDA ratio is the amount total debt being senior debt plus subordinated debt divided by earnings before interest, taxes, depletion, depreciation and amortization

and is used by us to assess our compliance under credit agreements. There is no subordinated debt outstanding or forecast in the Long-Term Plan.

http://www.sedar.com/

http://www.sec.gov/


Forward-Looking Information Advisory

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", "illustrative", "may",

"will", "project", "could", "plan", "intend", "should", "believe", "outlook", "objective", "aim", "potential", "target", "seek", "budget", "predict", "might" and similar words and derivatives thereof

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:

all details of, all projections of future activities related to, and all expectations of our performance and results as a result of executing, our long term plans, strategies and goals, and the benefits

anticipated to accrue to us and our securityholders as a result thereof; future cash dividend payments, including the maintenance of a quarterly cash dividend at current levels in the future;

updated 2013 guidance with respect to expected annual average production, exit production and capital expenditure levels; the conclusions reached from our strategic review process, namely our

long-term plan to focus on: (i) core areas of expected highest return, namely the Cardium, Viking and Slave Point plays; (ii) debt reduction through focused dispositions and redeployment of funds

to core projects; (iii) sustainable dividends; (iv) execution of an optimized strategy through cost reductions, operational excellence and improving capital efficiencies; (v) non-core asset

rationalization, focusing asset portfolio on three to four core areas with proceeds being used to reduce debt; and (vi) improving oil production and funds flow compound annual growth rates

("CAGR"); our focus on shareholder value through improved capital efficiencies, improving the balance sheet, managing the asset portfolio and improving costs and netbacks; certain metrics that

we are targeting to improve, namely debt to funds flow, repeatable sustainability ratio, in-play cost and recovery metrics, reserve replacement, development costs per boe, proceeds from asset

sales by 2015, new production adds, focus of operated development drilling capital program, cost controls and per barrel netback CAGR; our plan to continue with our capital program

optimization, portfolio rationalization and the expected amount of proceeds from dispositions and the timing thereof; the overview of our long-term plan, namely: (i) prioritizing light oil development;

(ii) focus on the Cardium play with a view to increasing annual capital spending on that play to $800 million by 2018; (iii) capturing the superior economics of the Viking play early in the long-term

plan; (iv) growing the Slave Point program as funds flow grows, reaching about $450 million of annual capital expenditures in five years; and (v) focusing on the importance of 2014 as a critical

transition year with respect to assets sales, restoring the balance sheet and fully ingraining a high performance culture; our expected oil production growth, netback growth and subsequent

improved funds flow per debt adjusted share CAGR; our focus on our balance sheet and details of anticipated dispositions and amounts thereof; funding of future growth and dividends; targeted

long-term sustainability ratio; our expectation that there will be no concerns with the debt to capitalization covenant contained in both our credit facility and private notes through 2018; our targeted

debt reduction, debt capital forecast, senior debt to EBITDA and debt to funds flow ratios (post planned dispositions); the potential alternative to refinance our outstanding notes in the private

market; our views on our note maturity profile, the ability to use bank debt capacity to repay maturities and capacity to add term as maturities near created by the limited notes due 2021; matters

related to Phase 1 of our acquisition and divesture ("A&D") strategy, the expected characteristics and timing thereof and proceeds therefrom and the value proposition from the agreements

reached; matters related to Phase 2 of our A&D strategy, including the expected properties that may be involved, the expected marketing strategy to employ with respect thereto and the expected

impact that A&D activities will have on us; matters related to our long-term development plan and related development drilling capital, including our plan with respect to our investment program,

our views on the qualities and characteristics of our assets, our expected E&D capital over the next five years, including expected aggregate capital expenditures over five years for the Cardium

play, the Slave Point play and the Viking play, and our expected development production, D & C cost performance and well counts that will result from the foregoing capital program; matters

related to our views on our drilling inventory (and expected growth thereof) and expected internal rate of return ("IRR") on such drilling inventory, including the expected impact of enhanced oil

recovery ("EOR") projects over our asset base; expected development costs by core areas and reserves replacement ratios over the next five years; our views on our long-term plan and its

impact on us, including the quality of our capital programs and the expected metrics generated therefrom, the optimization of program selection on an economic basis (and expectations of that

yielding improved metrics), the integration of EOR plans into our development plans and the expected growth of development inventory beyond the long-term plan as resource development

continues; matters pertaining to our 2014 capital budget, including our focus on core oil resources and balance across all quarters and maximizing profitability and capital efficiency, our expected

capital expenditure levels in total and by area, the expected allocation of the budget and the expected number of wells to be drilled under the budget in total and by area, the expected divestment

of about 12,500 boe/d during 2014 and our annual average production forecast for 2014; our operated development capital, net production adds, gross well count, capital program, production

outlook and per well D&C cost performance in each of our core areas during the next five years; the expected ultimate recovery factor in each of our core areas; our ability to convert our

resources into reserves in each of our core areas during our five year plan and beyond and the potential amount of converted resources; matters related to our plan to improve costs and

netbacks, including expected total operating and net G&A costs and unit operating and G&A costs for the next five years (broken down by specific cost areas), the expected top five operating and

G&A cost drivers and the steps we plan to take to improve costs and netbacks, including implementing continual labour force and G&A analysis and optimization, electrical power management,

reliability and work-over operating philosophy, chemical program optimization, maintenance practices and spending awareness and industry and competitor bench marking; and our expectations

for the next five years for a number of financial and corporate metrics, including metrics related to field netbacks, liquids weighting, production, funds flow, debt to funds flow, operated

development capital, operating costs, debt and sustainability ratios, including four and five year CAGR figures for total production, oil production, funds flow, operating costs and debt.


Forward-Looking Information Advisory

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: future average operated development costs; the expected

terms and timing of asset sales to be completed in the fourth quarter of 2013 and in 2014, including the proceeds to be derived therefrom and the amount of production that will be disposed; our

ability to execute our long-term plan as described herein and the impact that the successful execution of such plan will have on us and our shareholders; the matters set forth under "Plan Pricing

Assumptions"; the laws and regulations with which we will be required to comply, including laws and regulations relating to taxation, royalty regimes and environmental protection; future capital

expenditure levels; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil prices; future crude oil,

natural gas liquids and natural gas production levels; drilling results; future exchange rates and interest rates; future debt levels; the amount of future cash dividends that we intend to pay and the

level of participation in our dividend reinvestment plan; the cost of expanding our property holdings; our ability to obtain equipment in a timely manner to carry out exploration and development

activities and the costs thereof; 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, including our ability to renew or replace our credit facility and our ability to finance the repayment of our senior unsecured notes on maturity; our ability to execute on planned

asset acquisition and divestment programs; our ability to add production and reserves through our development and exploitation activities; performance and decline rates of future development

wells; timing and costs of bringing future development wells on stream; the expected inventory of future drilling locations; reservoir response to water flood and other enhanced oil recovery

methods; our ability to access development and production locations; producing well and production equipment reliability and decline rates; operating and administrative cost savings; and

performance of non-operated properties. 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 possibility that we are unable to execute some or all of our ongoing non-core asset

disposition program on favourable terms or at all, whether due to the failure to receive requisite regulatory approvals or satisfy applicable closing conditions or for other reasons that we cannot

anticipate; the possibility that we will not be able to successfully execute our long-term plan in part or in full, and the possibility that some or all of the benefits that we anticipate will accrue to us

and our securityholders as a result of the successful execution of such plan do not materialize; 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 and political 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 crude

oil, natural gas liquids and natural gas, price differentials for crude oil produced in Canada as compared to other markets, and transportation restrictions; royalties payable in respect of our oil and

natural gas production and changes to government royalty frameworks; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in

foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including wild fires and

flooding); failure to obtain regulatory, industry partner and other third-party consents and approvals when required, including for acquisitions, dispositions and mergers; failure to realize the

anticipated benefits of dispositions, acquisitions, joint ventures and partnerships; changes in taxation and other laws and regulations that affect us and our securityholders; the potential failure of

counterparties to honour their contractual obligations; 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.com and 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.

Stock Exchange

Toronto: PWT

New York: PWE

Legal Counsel

Burnet, Duckworth & Palmer LLP

Independent Reserves Evaluator

Sproule Associates Limited

Transfer Agent

Canadian Stock Transfer Company

Toll Free: 1-800-387-0825

Email: [email protected]

Website: www.canstockta.com

Investor Relations

Clayton Paradis Manager, Investor Relations

Telephone: (403) 539-6343


Toll Free: 1-888-770-2633


Website: www.pennwest.com

Penn West

Suite 200, Penn West Plaza

207 – 9th Avenue SW

Calgary, Alberta, Canada T2P 1K3

Telephone: (403) 777-2707

Toll Free: 1-866-693-2707

Facsimile: (403) 777-2699

Website: www.pennwest.com

Documents

Corporate Presentation - Seeking Alpha · 3/28/2016 · Corporate Presentation January 2014 . pennwest.com | TSX ... See “Non-GAAP Measures Advisory”. ... Declared fourth quarter