June 2012 GHS100 Conference Presentation

An Intermediate-Sized

Real Growth Company Low Risk Oil Development

Robust at Low Prices

GH

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| J

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BUILDING A TOP TIER

ENERGY COMPANY,

ADDING MORE OIL,

BUILDING UP VALUE.

2 PACE OIL & GAS | GHS100 CONFERENCE SAN FRANCISCO | JUNE 2012

Forward Looking Statements

Forward-Looking Statements: This presentation contains certain forward-looking statements and forward-looking

information (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian

securities laws. All statements other than statements of present or historical fact are forward-looking statements. In some

cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "believes", "expects",

"intends", "projects", "plans", "anticipates", “positions”, “potential”, “objective”, “continuous”, “ongoing”, "estimates" or

"contains" or similar words or the negative thereof. In particular, this presentation contains forward-looking statements

relating to: the estimated production of Pace Oil & Gas Ltd. (“Pace”), the estimated reserves of Pace Oil & Gas Ltd., the

estimated pro-forma funds from operation of Pace Oil & Gas Ltd., the expected credit facility available to Pace Oil & Gas

Ltd., the anticipated number of wells and completions to be carried out, the anticipated replacement production from our

new completions, the expected reserve additions, future plans and expenditures of Pace Oil & Gas Ltd., the forecasted

commodity prices.

These statements represent management's expectations or beliefs concerning, among other things, future capital

expenditures and future operating results and various components thereof or the economic performance of Pace and

include, without limitation, statements with respect to the future financial position, business strategy, budgets, projected

costs and plans, objectives of or involving Pace or any of its respective affiliates; access to credit facilities; capital taxes;

income taxes; commodity prices; administration costs; commodity price risk management activities; expectation of future

production rates and components of cash flow and earnings. Actual events or results may differ materially. The

projections, estimates and beliefs contained in such forward-looking statements are based on management's estimates,

opinions and assumptions at the time the statements were made including assumptions relating to the production

performance of Pace’s oil and gas assets, the cost and competition for services throughout the oil and gas industry in

2012 and beyond and the continuation of the current regulatory and tax regime in Canada, and necessarily involve known

and unknown risks and uncertainties which may cause actual performance and financial results in future periods to differ

materially from any projections of future performance or results expressed or implied by such forward-looking statements.

Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those

predicted. Pace does not undertake to update any forward-looking information contained in this presentation whether as

to new information, future events or otherwise except as required by securities rules and regulations. Barrels of Oil

Equivalency: Barrels of oil equivalent (BOE's) may be misleading, particularly if used in isolation. In accordance with NI

51-101, a BOE conversion ratio for natural gas of 6 Mcf:1 bbl has been used, which is based on an energy equivalency

conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

PACE OIL & GAS | GHS100 CONFERENCE SAN FRANCISCO | JUNE 2012 3

Corporate Overview Strong Real Growth

Top tier growth – increasing oil weighting drives cash flow

Strong Performance Metrics – “Best in Class”

Operating results – Increased oil weighting – Op costs reduced

Execution Efficiency – Low finding costs – Top tier recycle

Significant Upside

Portfolio of top tier resource plays – Large OOIP

Multiple valued-added visible growth opportunities

Significant upside potential/large scale catalysts

Clear Path to Sustained Visible Oil Growth


Corporate Highlights Current – March 31, 2012

Basic Shares Outstanding (mm) 47.2

FD Shares Outstanding (mm) 50.7

Bank Debt (mm) $168

Net Debt (mm) $213

Credit Facility (mm) (1) $300

Proved Reserves (mmboe) (2) 44.4

2P Reserves (mmboe) (2) ~50% Oil 69.6

Q1 2012

2012

Outlook

Oil & NGLs (bbls/d) 7,192 7,000 - 7,300

Natural Gas (mmcf/d) 44.2 41 - 44

CapEx 2012 (mm) 41.9 ~ $85

Production Mix ~ 50% Oil 50% - 52% Oil 1. Banking syndicate - CIBC, NBF, BMO, BNS, HSBC, ATB – renewed June 2012

2. Reserves December 31, 2011 evaluated by McDaniels & Associates Consultants Ltd.


Corporate Growth Strategy

Near Term (1-2 years)

Oil Focused – maintain Gas option

Mid Term (2-4 years)

Advance Oil add Gas/Liquids

Long Term (5+ years)

Balanced Oil & Gas/Liquids

Exploit and develop existing oil assets

Explore and develop oil resource plays in inventory

Identify new oil resource plays/concepts

Maintain/Rank best gas resource opportunities

Engineered oil enhancements – Waterflood/ASP

Acquire strategic synergetic opportunities

Expand resource opportunity base

Full scale development of resource assets

Apply technology to enhance recovery and production

Monitor and identify the key innovative technologies

EOR potential additions of over 40 mmbbls

Oil resource play potential of 50-250 mmbbls

Focus on Oil – Exploitation and development – Dixonville staged development (acceleration), Southern

Alberta Glauconitic/Mannville, Mississippian and Waterfloods, Red Earth Slave Point

Focus on Oil/Liquids rich gas – Haro Pekisko, Southern Alberta Mannville, Mississippian and

Waterfloods/ASP – Dixonville acceleration/ASP, New Oil Resource Plays/New EOR Technologies


3,531 3,542 4,668

5,391 5,868 6,077 6,061

6,965 7,192

9,808 10,271

12,403

13,089

14,141 14,262

13,558

14,205 14,557

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000Gas (boe/d)

Oil+NGL (bbls/d)

Oil Growth Drives Production Increase

Total production up

over 48% from Q1

2010

Oil production up

over 100% to 7,200

bbls/d Q1 2012

Strong oil growth

(15%+ y/y) drives

production growth

Only 3% NGL in Oil Total

Steady paced oil growth trend


2011 Reserves Breakdown

Reserves by Product

(boe@6:1, P+P)

Reserves by Category

($, NPV 10% Disc)

Net Present Value by Product

($, P+P, 10% Disc)

NGL 2%

Oil 48%

Gas 50%

NGL 2%

Oil 75%

Gas 23%

63% PDP

14% PDNP PUD

23% Prob

Working Interest Reserves Oil NGL Natural Gas Total 10%

(mboe) (mboe) (mmcf) (mboe) ($mm)

Proved Developed Producing 18,456 564 82,169 32,715 530,440

Proved Developed Non Producing 2,498 107 18,704 5,722 73,668

Proved Undeveloped 2,593 62 20,022 5,993 49,883

Total Proved Future Development Capital (“FDC”)$97mm 23,548 734 120,895 44,430 653,991

Probables 10,100 534 87,403 25,201 193,462

Proved + Probables FDC of $191mm 33,647 1,268 208,298 69,632 847,454

63%

77%

1) Based on the December 31, 2011 McDaniel NI 51-101 compliant reserves evaluations

2) Columns may not add due to rounding


Proved PV10 $13.85 / share

Probable PV10 4.10 / share

2P PV10 $17.95 / share

Pace Underlying Value

Each common share owns

1.48 boe of reserves

(0.71 bbl of oil)

2011 Net Asset Value - ($mm) PDP Total Proved

Oil P+P

BT 10% reserve value (1) 530 534 $ 847

Less: net debt (186.1) (186.1) (186.1)

Add: undeveloped land value (354,000 acres @ $250/acre) (2) 88.5 88.5 88.5

Add: seismic and other assets 2.9 2.9 2.9

Net asset value $ 752.7

Shares outstanding (mm basic) 47.2 47.2 47.2

10 NAV/Share $9.22 $9.30 $ 15.95

(1) McDaniels & Associates Forecast Price & Costs (12/31/2011) Oil WTI 2012 - $97.50 & 2013 - $97.50, GAS AECO 2012 – $3.50 & 2013 – $4.20

(2) Internal value estimate

NGL 2%

Oil 75%

Gas 23%


Pace Delivers Low Finding Costs – Year / Year

$boe

2011 2010

Proved Proved

Plus

Probable

Proved Proved

Plus

Probable

F&D Costs $ 16.17 $ 17.04 $ 12.00 $ 17.20

A&D Costs $ 23.26 $ 7.36 $ 20.03 $ 14.93

FD&A Costs (including

changes in FDC)

$ 16.09 $ 17.36 $ 17.81 $ 15.39

%Adds by Product

Oil 79% 60% 140% 132%

Natural Gas 21% 40% (40%) (32%)

100% 100% 100% 100%

Pace consistently delivers low cost, high value Oil adds

Over 2.1 recycle ratio on weighted average netback by product


Low Finding Costs with Strong Oil Additions

AAV

NGL

ARX BXE BIR

PXX

BNE

CLT

CKE

CPG

LEG

NVA

PCE

POU

PGF

PBN

PRQ

TT

TET

WFE

BTE

TOU CQE

0

10

20

30

40

50

60

70

80

90

0% 20% 40% 60% 80% 100%

TP

F&

D (

$/b

oe)

% TP Oil & NGL Additions

2011 2010

AAV NGL ARX BXE

BIR

PXX BNE CLT

CKE

CPG

LEG

NVA

PCE

POU

PGF

PBN

PRQ TT

TET

WFE

BTE

TOU

0

10

20

30

40

50

60

70

80

90

0% 20% 40% 60% 80% 100%

TP

F&

D (

$/b

oe)

% TP Oil & NGL Additions

Below line = high recycle ratios

Oil weighted adds delivered “Best in Class” recycle ratios * Data from Canoils


Increased Liquids Increases Netbacks/Cash Flow

Steady growth in liquids

weighting compared to

peers

Increased operating

efficiencies & oil growth

deliver higher netbacks

Top tier cash flow per

share growth

* All estimates based on FirstEnergy Research June 14, 2012

FE Price Deck $105/bbl WTI, $2.25/mcf AECO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%2012e % Liquids

-40%

-20%

0%

20%

40%

60% CFPS Growth 11/10


Top Quality Reserves – Oil Weighted

-

5

10

15

20

25

30PDP Oil & NGLs

mm

bb

ls

Large and growing oil

reserves are low risk

Proved Developed

Producing

Large Proved Developed

Producing is increasingly

oil weighted

* Data from Canoils

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%Value Oil % of TP


Decreasing Op Costs & Increasing Op Netback

30% op cost reduction while increased oil weighting to 50%

$19.68

$17.24

$15.21

$13.81 $13.51 $13.20 $13.38 $13.84

Q1 10 Q2 10 Q3 10 Q4 10 Q1 11 Q2 11 Q3 11 Q4 11

Operating Costs/boe

$16.57

$14.99 $15.20

$19.55

$20.77

$24.11

$20.40

$24.18

Q1 10 Q2 10 Q3 10 Q4 10 Q1 11 Q2 11 Q3 11 Q4 11

Operating Netbacks/boe


Operating Cost Reduction &

Solid Oil Weighted Reserves with Low Decline

0%

5%

10%

15%

20%

25%

30%

35%

40%

45% Base Decline %

* Data from XIT

-20%

-10%

0%

10%

20%

30%

40%

50%% change in Opex 2010 to 2011

17% operating cost

reduction while

increasing oil

production

Large legacy oil

pools - existing

waterflood & EOR

potential are platform

for low base decline

now and future


Significant Upside & Visible Long Term Growth Areas

Key Attributes

Play Type Project

Capital

MM$

Gross

Operated

Wells

Net Wells

Southern

Alberta

Glauconite

Lithic

Pekisko

Waterflood

$45 20 18.4

Dixonville Montney C

Waterflood

$10

Red Earth Slave Point $5

Northwest

Alberta

Pekisko $15 4 4

Total Oil $75 24 22.4

Deep Basin $5 - -

Land,

Seismic, G&A

other

$10

Grand Total $85 24 22.4

High Working Interest

Operational Control

CapEx to match Cash Flow

2012 CapEx directed towards oil program


Southern Alberta

Current production: 4,800 boe/d (44% oil)

• 2,100 bbls/d oil

Total Acreage

• Net 312,000 - 488 sections

2011 Program – Successful Oil Drilling

• Oil production up 30% from Q4 2010

Repeatable Drilling & EOR Potential

• 75 well inventory and growing

• Execution efficiency gains drive lower D,C & E costs

• 90 MMbbls DPIIP and growing

• Waterflood and ASP/tertiary potential

2012 Plan (~ $45 mm)

• Implement waterflood in NNN/BBB – commenced

Q1 2012

• 20 (18.4 net) oil drills – 6 (5.4 net) drilled in Q1 2012

• Other pool waterflood optimization

Key Attributes Glauconite & Mannville Oil Plays

High working interest with infrastructure

T10

T15

R20W4 R15W4


0

50

100

150

200

250

300

350

400

450

500

0 12 24

BO

E/D

Months

Southern Alberta – Drill Economics

Play Type Curve

D,C, Equip $1.9 mm

Production, boe/d (IP 30 day) 130

Reserves (mboe) 125

NPV 10%($mm/well) $2.0

Profit to Investment 1.05

Rate of Return 56%

Reserve Cost ($/boe) $15.25

Netback (1st year) ($/boe) $54.40

Type Curve

R19W4 R17W4

T14

T12

Successful 2011 drilling program drives oil growth

2012 Plan ($40 mm+/-)

• 20 (18.4 net) horizontal drills

• Expand current inventory of 75 wells

Average


1.20

0.10

0.14

0.10

0.10

0.76

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

Southern Alberta Cost Drivers - Pads

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

0 5 10 15 20 25

2011

Rig & Testing: $200k

Water: $50-75k

Frac: $175-225K

Drillout ports: $0-75k

Well Equip.: $75k

Total $525-$650k

- Remove frac strings

- Remove frac port drill outs

- Minimize testing

Q3 - 2012

- Slickwater fracs

- Water recycling

- Project frac execution

- Less than $400 K/well

Co

mp

leti

on

Co

st

($K

)

Target D,C,& E well cost from $1.9 MM/well to $1.2 - $1.4 MM/well

Q1 2012 average 1.8 MM/well

Drilling Costs Initiatives Completion Cost Initiatives


Price/Capital Sensitivity – Southern Alberta

0

20

40

60

80

100

120

140

1000 1200 1400 1600 1800 2000 2200

Costs expectations of

$1.2 to $1.4 MM/well

by 2013

Returns above 60%

Higher returns

compounded with

capital reduction

SAB - Capital Sensitivity

IRR

,%

Capital $K/Well

-

10

20

30

40

50

60

70

80

90

40 50 60 70 80 90 100

Break even price of

$45/bbl at current

capital cost

Break even of

<$30/bbl with target

cost reductions

Price Sensitivity (Oil)

Hardisty Bow River 25API (AB) - $20/bbl offset

IRR

,%

Wellhead Price, $/bbl

150 Mboe

125 Mboe

100 Mboe

95%


Waterflood Management Opportunities

Implement waterflood in NNN/BBB

• 400 bbl/d production adds forecasted

• 52% IRR, 1.5 mmbbls PDP additions

Infill horizontals possible once

pressures restored

Other pool waterflood optimization

Additional ASP potential

-1000

0

1000

2000

3000

4000

5000

0

200

400

600

800

1000Retlaw Unit WF Forecast

Cal Day Oil

Water Inj, bwpd

R17W4 R18W4

T13

T12

2012 Plan ($5 mm net capital)


Taber South Full Life Example

(A)Strong early waterflood response

(B)Low mid life declines

(C) significant ASP uplift

A B C


Peace River Arch - Dixonville Key Attributes


• Netback over ~ $35/boe*

Total Acreage

• Net 58,500 - 91 sections

Montney “C” Oil Pool with expanding waterflood

• OOIP increased by 25% to 188 mmbbls – 30 API oil

• 100% Pace working interest

• Incremental 20,000 bbls/d fluid capacity

• Tertiary potential – ASP in 2014

2011 Program – Continued successful

waterflood

• Oil Production up 36% from Dec. 2010

Large Reserve Upside

• 2P remaining reserves 23 mmboe (15% recovery)

• 2011 TP reserve adds 3.6 mmboe

2012 Plan ($10 mm)

• Expand waterflood on remaining 1/3 of pool

• 17 injector conversions

• Continue well pump upsizes

Strong waterflood response

continues

to drive increased oil production

R1W6 R25W5

T87

T86


Dixonville: Montney C Reservoir Simulation

Waterflood response exceeds base case (booked reserves) and current model

3,200 bbls/d

Prod, 5.7 Prod, 5.7 Prod, 5.7

1P, 16.2 1P, 16.2 1P, 16.2

2P, 7.0 2P, 7.0 2P, 7.0

Upside, 9.4 Upside, 9.4

Tertiary, 28.2

15%

20%

35%

-

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0

10

20

30

40

50

60

70

Base Case WaterfloodOptimization

EUR (SP)

ULT

IMA

TE R

ECO

VER

Y O

F O

OIP

(%

)

REM

AIN

ING

REC

OV

ERA

BLE

OIL

(M

MB

BL)

DIXONVILLE: MONTNEY C

Prod 1P 2P Upside Total OOIP Rec.


Peace River Arch - Red Earth Area

Southern Alberta

Current Production: 550 bbls/d (oil)

Total Acreage

• Net 50,250 – 78 sections

Top Quality light oil property

• Netback > $60/boe*

Slave Point Resource Play

• High industry activity

• Gross 42,800 (32,200 net) acres

2013 Plan ($15-20 mm)

• Create Slave Point program for 2013

• Current inventory of 50 wells & growing

• Monitor industry activity/performance

• No material near term expiries

Key Attributes

T88

R7W5

T86

R9W5


Peace River Arch - Red Earth Area - Economics

0 1 2 3

Oil

Ra

te (

bb

l/d

)

Years

100/1-9-88-8W5/0

100/8-1-88-12W5/0

Southern Alberta

Play Type Curve

D,C, Equip $3.0 mm

Production, boe/d (IP 30 day) 125 - 150

Reserves (mboe) 150

NPV 10%($mm/well) $2.1

Profit to Investment 0.7

Rate of Return 50%

Reserve Cost ($/boe) $20.00

Netback (1st year) ($/boe) $73.00

Type Curve

1st Generation Wells

2011 Wells

R10W5 R6W5

T85

T87

T89


Northern Alberta: Rainbow/Haro – Resource play

Key Attributes


Total Acreage • Gross 366,000 - 572 sections

• Net 319,000 - 498 sections

Production Optimization

• 925 bbl/d Muskeg & Keg River sweet crude

• Oil production up 40% from Dec 2010

• Large low decline (5-7%/yr) Bluesky gas

Haro – early stage oil resource play

• 1.16 B bbls DPIIP, Net 71,000 acres – 111 sections

• 22º API with cold production

• Potential 4-8 wells per section

• 500 m depth – low capital cost per well

2012 Plan (~ $15 mm)

• Drilled 4 & completed 3 horizontal wells

• Pace activity continues land for 5 years

• ARC drilled 4 Pekisko wells this winter

(1) Discovered petroleum initially-in-place

R10W6 R6W6 R2W6

T110

T105

T100


Haro Pekisko Encouragement

Unrisked 300 to 1600 locations

0

25

50

75

100

125

150

175

200

0 12 24 36

Oil R

ate

(b

bl/d

)

Months

Type Curve 00/02-36

D,C, Equip $2.1 – 2.5 mm

Production, boe/d (IP 30 day) 100 - 125

Reserves (mboe) 100 - 150

NPV 10%($mm/well) $2.0 – 2.4

Profit to Investment 0.8 – 1.1

Rate of Return 35 - 75%

Reserve Cost ($/boe) $14 - 25

Netback (1st year) ($/boe) $55 - 60

2-36-101-5W6

T100

T98

T102

R5W6 R3W6


Haro Drilling Initiatives

1.90

0.30

0.15

0.20

0.15

1.10

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

$M

M

2011 completion costs

• $1.2 - $1.5 MM/well

Initiatives:

• Build water pits

• Expand water disposal &

reduce trucking

• Roads for access

Future completion costs

• $0.8 to $1.0 MM/well

Target D,C,& E well cost of $1.9 to $2.1 MM/well

Drilling Cost Initiatives Completion Cost Initiatives


Price/Capital Sensitivity

Costs expectations of

<$2.1 DC&E 2014+

Returns above 35%

Road & pad scouting

on going

Break even price

$45 - $55/bbl

with drill, complete,

equipment cost of

$2.1 MM/well

0

25

50

75

100

125

150

2.0 2.5 3.0 3.5

-

20

40

60

80

100

120

40 50 60 70 80 90 100

Price Sensitivity (Oil) at $2.1 MM well

Haro - Capital Sensitivity

22 API (AB) - $25/bbl offset

IRR

,%

IRR

,%

Capital $MM/Well

Wellhead Oil Price, $/bbl


Large Repeatable Gas

Current Production: ~ 7.6 mmcf/d

16,300 Chinook Ridge

Deep Basin Land

Elmworth 3,500

Red Rock 19,000

Bilbo 5,400

5,800

27,000

20,100

15,400

Gross Acres Net Acres Area

Total 68,300 44,200

Working interest: 75%-100% (operated)

Net acreage: 19,300 acres (30.2 sections)

Large scale area development ongoing

Farrell Creek, BC


Deep Basin Multi-Zone Gas Resource Play PROSPECTIVE

LAND

NUMBER OF WELLS AND COST

PER WELL UNRISKED POTENTIAL

Area Zone

Pace Net

Sections Of

Land

Wells Per

Section

Net Original

Unrisked

Drilling

Inventory

Net

Book-

ed

Loca-

tions

Net Unbooked

Unrisked

Remaining

Locations

Est. Drill,

Complete and

Tie-in per

well ($MM)

Net Unrisked Capital

Inventory ($MM)

Pace WI EUR (1)

(Bcf)

Natural Gas Resource Plays

Bilbo Falher G HZL 10 2 - 3 20 - 30 0 20 - 30 $6.0 120 - 180 TBD

Red Rock &

Bilbo

Cadomin HZL &

Uphole

Cretaceous

40 3 - 4 120 - 160 0 120 - 160 $7.0 840 - 1120 600 - 800

Red Rock &

Bilbo Nikanassin (Vt.) 40 2 - 3 80 - 120 3.8 76 - 116 $6.0 456 - 695 400 - 600

Elmworth

Cadomin HZL &

Uphole

Cretaceous

5.5 2 - 3 11 - 17 5.3 6 - 11 $6.0 34 - 70 50 - 80

Chinook Ridge Nikanassin (Vt.) 20 2 - 3 40 - 60 2.3 38 - 58 $6.0 230 - 345 200 - 300

Chinook Ridge

Cadomin HZL &

Uphole

Cretaceous

20 2 - 3 40 - 60 0 40 - 60 $7.0 280 - 420 200 - 300

Moberly/Farrell

Creek

Montney - Doig

HZL 30 4 - 8 120 - 240 0 120 - 240 $6.0 720 - 1,440 720 - 1,440

Moberly/Farrell

Creek Phosphate HZL 30 2 - 3 60 - 90 0 60 - 90 $5.8 348 - 522 360 - 540

Total (+/-) 491 - 777 11.4 480 - 765 3,030 - 4,790 2,530 - 4,080

TCF 2.5 - 4.0 *Amounts above may not add due to rounding

• Over 700 potential drilling locations

• 11.4 net locations booked in the reserve report (< 2% of potential)

• Potential to add 4 Tcf of reserves (est. ~$5.0B investment) (1) Net EUR means Pace's share of estimated ultimate recovery and are not NI 51-101 compliant


Pace Oil Enhanced Recovery

Large oil in place with low 2P recovery factors

Potential to add significant barrels through enhanced mechanisms

Gross

Pace

Incr.

Recovery OOIP Prod. Recovery Pace WI TP 2P Upside

Area / Pool Mechanism (mmbbls) (mmbbls) (% OOIP) (% OOIP) (mmbbls) (% OOIP) (mmbbls) (% OOIP) (mmbbls) (mmbbls) (% OOIP) (%) (mmbbls) (mmbbls) (mmbbls)

Dixonville Montney C Waterflood 188 5.7 3.0% 11.7% 21.9 15.4% 29 5.0% 9 38 20.4% 100% 16.2 23.2 9

Polymer - SP 15.0% 28 67 35.4% 28

Southern Alta Waterflood 91 14.5 16.0% 20.5% 18.6 22.1% 20 6.9% 6 26 29.0% 66% 2.0 2.7 4

Total Waterflood 279 20.2 7.3% 14.5% 40.5 17.6% 49 5.6% 16 65 23.2% 18.2 25.9 13

Total Surfactant-Polymer 212 15.0% 32 76 35.7% 30

Total Conventional 279 20.2 7.3% 14.5% 40.5 17.6% 49 17.0% 47 140 50.3% 18.2 25.9 44Haro Pekislo Resource Primary 1,160 5.0% 58 58 5.0% 100% 58

Solvent/Thermal 15.0% 174 174 15.0% 100% 174

Total - Haro Resource 1,160 20.0% 232 232 20.0% 232

Total Pace Upside 275.9

Pace WI as of Dec.

31, 2011

Cum as of Dec.

31/2011

Upside PotentialTotal Proved (2P + Upside)

Estimated Gross Ultimate Recovery Total Gross EUR

Proved + Probable


Key Investment Highlights

Strong Real Growth • Oil weighting up and Oil weighting growing

Strong Performance Metrics – “Best in Class” • Solid operating results and Execution Efficiency

• Increased oil weighting and op cost reduction

Solid low risk high value oil reserve additions

Significant Upside • Identified portfolio of visible long term, low risk,

oil growth opportunities

Oil resource play potential plus large scale enhanced recovery

upside

Oil Weighted (Real) Growth,

Excellent Results, Excellent Potential


Hedging

Commodity Term Type Volume Price

(CDN$)

Oil 2012 fiscal Collar 500 bbl/d $95.00 to $117.75

Oil 2012 fiscal Collar 500 bbl/d $100.00 to 108.70

Oil 2012 fiscal Swap 1,500 bbl/d $97.07

Natural Gas Jun - Dec 2012 Swap 4,740 mcf/d $2.37/mcf

Natural Gas 2013 fiscal Swap 4,740 mcf/d $3.23/mcf

Natural Gas 2013 fiscal Collar 4,740 mcf/d $2.90 to $3.56/mcf

35 PACE OIL & GAS | GHS100 CONFERENCE SAN FRANCISCO | JUNE 2012

Pace Corporate Information Management

Fred Woods President & CEO

Todd Brown Vice President & COO

Chad Kalmakoff Vice President, Finance & CFO

Volker Braun Vice President, Exploration

Colin Merrick Vice President, HR, IR & Administration

Darrell Osinchuk Vice President, Exploitation

Martin Saizew Vice President, Engineering

Andrew Weldon Vice President, Business Development

Directors

Fred Woods Tom Simons

Tom Buchanan Jeff Smith

Peter Harrison Jay Squiers

Mike Shaikh David Tuer

Banking Syndicate

CIBC

National Bank

Bank of Montreal

Bank of Nova Scotia

Alberta Treasury Branches

HSBC Bank of Canada

Auditors

PriceWaterhouse Coopers LLP

Legal Counsel

Heenan Blaikie LLP

Evaluation Engineers

McDaniels & Associates Consultants Ltd.

Registrar & Transfer Agent

Computershare Trust Company of Canada

TSX Listing Symbol OTC Pinks Symbol

PCE PACEF

Address

Livingston Place, West Tower

Suite 1700, 250 – 2nd Avenue SW

Calgary, Alberta, Canada T2P 0C1

Ph: 403-303-8500

Investor Relations Email: [email protected]

Website: www.paceoil.ca

For Information Contact

Fred Woods President & CEO

Todd Brown VP & COO

Chad Kalmakoff VP, Finance & CFO

Main: 403-303-8500

Investor Relations Email: [email protected]

Website: www.paceoil.ca

TSX: PCE OTC: PACEF

June 2012 GHS100 Conference Presentation

Business

oil exploitation

operation of pace oil

expenditures of pace

pace oil gasltd

existing oil assetsoil

oil weighting op costs

barrels of oil equivalent

gas option